Table of Contents


 


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
ý☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20172020
or
¨☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
ENERGY TRANSFER EQUITY, L.P.LP
(Exact name of registrant as specified in its charter)
 
Delaware 30-0108820
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
8111 Westchester Drive, Suite 600, Dallas, Texas75225
(Address of principal executive offices) (zip code)
(214) (214) 981-0700
(Registrant’s telephone number, including area code)
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.  Yesý    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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yesý    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 the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerý 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  ý
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common UnitsETNew York Stock Exchange
At November 3, 2017,July 31, 2020, the registrant had 1,079,185,0302,695,845,699 Common Units outstanding.
 

FORM 10-Q
ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
TABLE OF CONTENTS
PART I — FINANCIAL INFORMATION
 
  
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
 
  
Consolidated Balance Sheets
1
  
Consolidated Statements of Operations
3
  
Consolidated Statements of Comprehensive Income (Loss)
4
  
Consolidated StatementStatements of Equity
5
  
Consolidated Statements of Cash Flows
6
  
Notes to Consolidated Financial Statements
7
  
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
4236
  
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
59
ITEM 4. CONTROLS AND PROCEDURES
61
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
61
ITEM 1A. RISK FACTORS
62
  
ITEM 6. EXHIBITS4. CONTROLS AND PROCEDURES
6264
  
SIGNATUREPART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
6365
ITEM 1A. RISK FACTORS
65
ITEM 6. EXHIBITS
66
SIGNATURE
67




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Forward-Looking StatementsDefinitions
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity”References to the “Partnership” or “ETE”) in periodic press releases and some oral statements of“ET” refer to Energy Transfer Equity officials during presentations aboutLP. In addition, the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, estimated or expressed, forecasted, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2016 filed with the Securities and Exchange Commission on February 24, 2017 and “Part II — Item 1A. Risk Factors,” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed on May 4, 2017.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
 AmeriGas/d AmeriGas Partners, L.P.per day
    
 AOCI accumulated other comprehensive income (loss)
    
 BblsBBtu barrelsbillion British thermal units
   
 Btu British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
    
 CitrusCitrus, LLC
DOJ U.S. Department of Justice
    
 EPA U.S. Environmental Protection Agency
    
 ETLP Credit FacilityETO Energy Transfer LP’s $3.75 billion revolving credit facilityOperating, L.P..
    
 ETPETO Series A Preferred Units Energy Transfer Partners, L.P. subsequent to the close of the merger of Sunoco Logistics Partners L.P. and Energy Transfer Partners, L.P.ETO’s 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETO Series B Preferred UnitsETO’s 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETO Series C Preferred UnitsETO’s 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETO Series D Preferred UnitsETO’s 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETO Series E Preferred UnitsETO’s 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETO Series F Preferred UnitsETO’s 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
ETO Series G Preferred UnitsETO’s 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
    
 ETP GP Energy Transfer Partners GP, L.P., the general partner of ETP
ETP HoldcoETP Holdco Corporation
ETP LLCEnergy Transfer Partners, L.L.C., the general partner of ETP GPETO
    
 Exchange Act Securities Exchange Act of 1934
    
 FEPFayetteville Express Pipeline LLC
FERC Federal Energy Regulatory Commission
FGTFlorida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus
    
 GAAP accounting principles generally accepted in the United States of America
    
 IDRsHFOTCO incentive distribution rightsHouston Fuel Oil Terminal Company, a wholly-owned subsidiary of ETO, which owns the Houston Terminal
    
 Lake Charles LNG Lake Charles LNG Company, LLC, a wholly-owned subsidiary of ETO
LE GPLE GP, LLC, the general partner of ET
    
 LIBOR London Interbank Offered Rate
    
 MMBtuMBbls million British thermal unitsthousand barrels
MEPMidcontinent Express Pipeline LLC
    
 MTBE methyl tertiary butyl ether
  �� 
 NGL natural gas liquid, such as propane, butane and natural gasoline
   
 NYMEX New York Mercantile Exchange

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 OSHA Federal Occupational Safety and Health Act
   
 OTC over-the-counter
    

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 Panhandle Panhandle Eastern Pipe Line Company, LP
PCBspolychlorinated biphenyl and its subsidiaries, wholly-owned by ETO
   
 PES Philadelphia Energy Solutions
PennTexPennTex Midstream Partners, LP
Preferred UnitsETP Series A cumulative convertible preferred units Refining and Marketing LLC
    
 Regency Regency Energy Partners LP
    
 Rover Rover Pipeline LLC
    
 SEC Securities and Exchange Commission
    
 SemCAMSSemCAMS Midstream ULC, a less than wholly-owned subsidiary of ETO
SemGroupSemGroup, LLC (formerly SemGroup Corporation)
Series A Convertible Preferred Units ETEET Series A convertible preferred units
    
 Sunoco Logistics Operations Sunoco Logistics Partners L.P.Operations L.P, a wholly-owned subsidiary of ETO
    
 Sunoco LPR&M Sunoco LP (previously named Susser Petroleum Partners, LP)(R&M), LLC (formerly Sunoco, Inc. (R&M))
    
 Transwestern Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of ETO
    
 Trunkline Trunkline Gas Company, LLC, a wholly-owned subsidiary of Panhandle
    
 WMBUSAC The Williams Companies, Inc.USA Compression Partners, LP, a wholly-owned subsidiary of ETO
USAC Preferred UnitsUSAC Series A Preferred Units
White CliffsWhite Cliffs Pipeline
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.


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PART I —– FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
September 30, 2017 December 31, 2016June 30,
2020		 December 31, 2019*
ASSETS      
Current assets:      
Cash and cash equivalents$469
 $463
$155
 $291
Accounts receivable, net3,551
 3,557
2,955
 5,038
Accounts receivable from related companies90
 47
140
 159
Inventories1,957
 2,103
1,593
 1,532
Income taxes receivable68
 146
Derivative assets42
 21
14
 23
Other current assets433
 503
231
 275
Current assets held for sale4,147
 291
Total current assets10,689
 6,985
5,156
 7,464
      
Property, plant and equipment68,730
 61,158
92,269
 89,790
Accumulated depreciation and depletion(9,463) (7,905)(17,328) (15,597)
59,267
 53,253
74,941
 74,193
      
Advances to and investments in unconsolidated affiliates3,177
 3,040
3,311
 3,460
Lease right-of-use assets, net1,112
 964
Other non-current assets, net891
 816
1,512
 1,571
Intangible assets, net6,195
 5,489
6,007
 6,154
Goodwill5,161
 5,170
3,868
 5,167
Non-current assets held for sale—
 4,258
Total assets$85,380
 $79,011
$95,907
 $98,973

*As adjusted. See Note 1.

ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in million)
(unaudited)

September 30, 2017 December 31, 2016June 30,
2020		 December 31, 2019*
LIABILITIES AND EQUITY      
Current liabilities:      
Accounts payable$3,994
 $3,502
$2,137
 $4,118
Accounts payable to related companies46
 42
16
 31
Derivative liabilities129
 172
24
 147
Operating lease current liabilities54
 60
Accrued and other current liabilities2,881
 2,367
2,738
 3,342
Current maturities of long-term debt716
 1,194
34
 26
Liabilities associated with assets held for sale81
 —
Total current liabilities7,847
 7,277
5,003
 7,724
      
Long-term debt, less current maturities44,495
 42,608
51,251
 51,028
Long-term notes payable – related company—
 250
Non-current derivative liabilities132
 76
577
 273
Non-current operating lease liabilities903
 901
Deferred income taxes5,027
 5,112
3,313
 3,208
Other non-current liabilities1,218
 1,055
1,218
 1,162
Liabilities associated with assets held for sale—
 68
      
Commitments and contingencies
 

 

Preferred units of subsidiary—
 33
Redeemable noncontrolling interests21
 15
750
 739
      
Equity:      
General Partner(3) (3)
Limited Partners:      
Common Unitholders(1,566) (1,871)19,843
 21,935
Series A Convertible Preferred Units377
 180
Total partners’ deficit(1,192) (1,694)
Noncontrolling interest27,832
 24,211
General Partner(7) (4)
Accumulated other comprehensive loss(21) (11)
Total partners’ capital19,815
 21,920
Noncontrolling interests13,077
 12,018
Total equity26,640
 22,517
32,892
 33,938
Total liabilities and equity$85,380
 $79,011
$95,907
 $98,973
*As adjusted. See Note 1.

ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
(unaudited)

Three Months Ended
September 30,		 Nine Months Ended
September 30,		Three Months Ended
June 30,		 Six Months Ended
June 30,
2017 2016 2017 20162020 2019* 2020 2019*
REVENUES       
REVENUES:       
Refined product sales$2,000
 $4,477
 $5,232
 $8,203
Crude sales1,329
 4,346
 4,872
 7,871
NGL sales1,254
 1,996
 2,943
 4,398
Gathering, transportation and other fees2,137
 2,035
 4,522
 4,302
Natural gas sales$1,098
 $1,070
 $3,132
 $2,603
514
 763
 1,102
 1,727
NGL sales1,749
 1,249
 4,782
 3,339
Crude sales2,273
 1,649
 6,751
 4,572
Gathering, transportation and other fees1,068
 1,028
 3,244
 3,118
Refined product sales2,706
 2,243
 7,928
 6,249
Other580
 466
 1,800
 1,346
104
 260
 294
 497
Total revenues9,474
 7,705
 27,637
 21,227
7,338
 13,877
 18,965
 26,998
COSTS AND EXPENSES       
COSTS AND EXPENSES:       
Cost of products sold7,078
 5,776
 21,028
 15,430
4,117
 10,301
 12,408
 19,778
Operating expenses636
 526
 1,779
 1,540
770
 792
 1,649
 1,600
Depreciation, depletion and amortization632

548
 1,840
 1,596
936

785
 1,803
 1,559
Selling, general and administrative142
 209
 484
 515
175
 179
 379
 326
Impairment losses4
 —
 1,329
 50
Total costs and expenses8,488
 7,059
 25,131
 19,081
6,002
 12,057
 17,568
 23,313
OPERATING INCOME986
 646
 2,506
 2,146
1,336
 1,820
 1,397
 3,685
OTHER INCOME (EXPENSE)       
Interest expense, net(505) (474) (1,471) (1,336)
OTHER INCOME (EXPENSE):       
Interest expense, net of interest capitalized(579) (578) (1,181) (1,168)
Equity in earnings of unconsolidated affiliates92
 49
 228
 205
85
 77
 78
 142
Impairment of investment in an unconsolidated affiliate—
 (308) —
 (308)
Losses on extinguishments of debt—
 —
 (25) —
—
 —
 (62) (18)
Losses on interest rate derivatives(8) (28) (28) (179)(3) (122) (332) (196)
Other, net76
 55
 168
 98
(68) 46
 (65) 42
INCOME (LOSS) BEFORE INCOME TAX BENEFIT641
 (60) 1,378
 626
Income tax benefit(157) (89) (97) (151)
INCOME FROM CONTINUING OPERATIONS798
 29
 1,475
 777
Income (loss) from discontinued operations, net of income taxes6

12
 (264)
24
NET INCOME804
 41
 1,211
 801
Less: Net income (loss) attributable to noncontrolling interest552
 (168) 508
 39
NET INCOME ATTRIBUTABLE TO PARTNERS252
 209
 703
 762
General Partner’s interest in net income1
 —
 2
 2
Convertible Unitholders’ interest in income11
 2
 25
 3
Limited Partners’ interest in net income$240
 $207
 $676
 $757
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:       
INCOME (LOSS) BEFORE INCOME TAX EXPENSE771
 1,243
 (165) 2,487
Income tax expense99
 34
 127
 160
NET INCOME (LOSS)672
 1,209
 (292) 2,327
Less: Net income attributable to noncontrolling interests306
 317
 185
 614
Less: Net income attributable to redeemable noncontrolling interests13
 13
 25
 26
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS353
 879
 (502) 1,687
General Partner’s interest in net income (loss)—
 1
 (1) 2
Limited Partners’ interest in net income (loss)$353
 $878
 $(501) $1,685
NET INCOME (LOSS) PER LIMITED PARTNER UNIT:       
Basic$0.22
 $0.20
 $0.64
 $0.72
$0.13
 $0.33
 $(0.19) $0.64
Diluted$0.22
 $0.19
 $0.62
 $0.71
$0.13
 $0.33
 $(0.19) $0.64
NET INCOME PER LIMITED PARTNER UNIT:       
Basic$0.22
 $0.20
 $0.63
 $0.72
Diluted$0.22
 $0.19
 $0.61
 $0.71
*As adjusted. See Note 1.


ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
(unaudited)
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Net income$804
 $41
 $1,211
 $801
Other comprehensive income (loss), net of tax:       
Change in value of available-for-sale securities2
 —
 5
 5
Actuarial gain (loss) relating to pension and other postretirement benefit plans5
 —
 2
 (3)
Foreign currency translation adjustments—
 —
 —
 (1)
Change in other comprehensive income (loss) from unconsolidated affiliates—
 2
 (1) (9)
 7
 2
 6
 (8)
Comprehensive income811
 43
 1,217
 793
Less: Comprehensive income (loss) attributable to noncontrolling interest559
 (166) 514
 31
Comprehensive income attributable to partners$252
 $209
 $703
 $762
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2020 2019* 2020 2019*
Net income (loss)$672
 $1,209
 $(292) $2,327
Other comprehensive income (loss), net of tax:       
Change in value of available-for-sale securities9
 3
 —
 8
Actuarial gain related to pension and other postretirement benefit plans8
 3
 11
 10
Foreign currency translation adjustments30
 —
 (34) —
Change in other comprehensive loss from unconsolidated affiliates—
 (5) (16) (9)
 47
 1
 (39) 9
Comprehensive income (loss)719
 1,210
 (331) 2,336
Less: Comprehensive income attributable to noncontrolling interests306
 317
 185
 614
Less: Comprehensive income attributable to redeemable noncontrolling interests13
 13
 25
 26
Comprehensive income (loss) attributable to partners$400
 $880
 $(541) $1,696
*As adjusted. See Note 1.

ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTSTATEMENTS OF EQUITY
FOR THE NINESIX MONTHS ENDED SEPTEMBERJUNE 30, 20172020 AND 2019
(Dollars in millions)
(unaudited)
 Common Unitholders General Partner AOCI Noncontrolling Interests Total
Balance, December 31, 2019*$21,935
 $(4) $(11) $12,018
 $33,938
Distributions to partners(1,591) (1) —
 —
 (1,592)
Distributions to noncontrolling interests—
 —
 —
 (444) (444)
Subsidiary units issued—
 —
 —
 1,580
 1,580
Capital contributions from noncontrolling interests—
 —
 —
 95
 95
Other comprehensive loss, net of tax—
 —
 (48) (38) (86)
Other, net22
 —
 —
 (7) 15
Net loss, excluding amounts attributable to redeemable noncontrolling interests(854) (1) —
 (121) (976)
Balance, March 31, 202019,512
 (6) (59) 13,083
 32,530
Distributions to partners9
 (1) —
 —
 8
Distributions to noncontrolling interests—
 —
 —
 (408) (408)
Capital contributions from noncontrolling interests—
 —
 —
 83
 83
Other comprehensive income, net of tax—
 —
 38
 9
 47
Other, net(31) —
 —
 4
 (27)
Net income, excluding amounts attributable to redeemable noncontrolling interests353
 —
 —
 306
 659
Balance, June 30, 2020$19,843
 $(7) $(21) $13,077
 $32,892
 General Partner     Common Unitholders     Series A Convertible Preferred Units Noncontrolling Interest Total    
Balance, December 31, 2016$(3) $(1,871) $180
 $24,211
 $22,517
Distributions to partners(2) (750) —
 —
 (752)
Distributions to noncontrolling interest—
 —
 —
 (2,180) (2,180)
Distributions reinvested—
 (173) 173
 —
 —
Subsidiary units issued—
 (56) (1) 1,692
 1,635
Issuance of common units—
 568
 —
 —
 568
Capital contributions received from noncontrolling interests—
 —
 —
 1,907
 1,907
PennTex unit acquisition—
 (2) —
 (278) (280)
Non-cash compensation expense, net of units tendered by employees for tax withholdings—
 —
 —
 69
 69
Sale of Bakken Pipeline interest—
 42
 —
 1,958
 2,000
Other comprehensive income, net of tax—
 —
 —
 6
 6
Other, net—
 —
 —
 (61) (61)
Net income2
 676
 25
 508
 1,211
Balance, September 30, 2017$(3) $(1,566) $377
 $27,832
 $26,640
 Common Unitholders General Partner AOCI Noncontrolling Interests Total
Balance, December 31, 2018*$20,773
 $(5) $(42) $10,291
 $31,017
Distributions to partners(799) (1) —
 —
 (800)
Distributions to noncontrolling interests—
 —
 —
 (425) (425)
Capital contributions from noncontrolling interests—
 —
 —
 140
 140
Sale of noncontrolling interest in subsidiary—
 —
 —
 93
 93
Other comprehensive income, net of tax—
 —
 8
 —
 8
Other, net17
 —
 —
 12
 29
Net income, excluding amounts attributable to redeemable noncontrolling interests807
 1
 —
 297
 1,105
Balance, March 31, 2019*20,798
 (5) (34) 10,408
 31,167
Distributions to partners(748) (1) —
 —
 (749)
Distributions to noncontrolling interests—
 —
 —
 (388) (388)
Subsidiary units issued—
 —
 —
 780
 780
Capital contributions from noncontrolling interests—
 —
 —
 66
 66
Other comprehensive income, net of tax—
 —
 1
 —
 1
Other, net50
 —
 —
 —
 50
Net income, excluding amounts attributable to redeemable noncontrolling interests878
 1
 —
 317
 1,196
Balance, June 30, 2019*$20,978
 $(5) $(33) $11,183
 $32,123
*As adjusted. See Note 1.

ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)
 Nine Months Ended
September 30,
 2017 2016
OPERATING ACTIVITIES   
Net income$1,211
 $801
Reconciliation of net income to net cash provided by operating activities:   
Impairment of investment in an unconsolidated affiliate—
 308
Loss (income) from discontinued operations264
 (24)
Depreciation, depletion and amortization1,840
 1,596
Deferred income taxes(120) (139)
Unit-based compensation expense76
 46
Inventory valuation adjustments(38) (203)
Equity in earnings of unconsolidated affiliates(228) (205)
Distributions from unconsolidated affiliates211
 190
Other(134) (197)
Net change in operating assets and liabilities, net of effects of acquisition222
 48
Net cash provided by operating activities3,304
 2,221
INVESTING ACTIVITIES   
Proceeds from Bakken Pipeline Transaction2,000
 —
Cash paid for acquisition of PennTex noncontrolling interest(280) —
Cash paid for acquisitions, net of cash received(293) (330)
Capital expenditures, excluding allowance for equity funds used during construction(6,102) (5,877)
Contributions to unconsolidated affiliates(230) (47)
Distributions from unconsolidated affiliates in excess of cumulative earnings115
 112
Other30
 58
Net cash used in investing activities(4,760) (6,084)
FINANCING ACTIVITIES   
Proceeds from borrowings23,988
 18,288
Repayments of long-term debt(22,586) (13,955)
Cash received from affiliate notes—
 1,606
Cash paid on affiliate notes(255) (1,607)
Subsidiary units issued for cash1,635
 2,097
Units issued for cash568
 —
Distributions to partners(752) (780)
Distributions to noncontrolling interest(2,156) (2,027)
Capital contributions received from noncontrolling interest919
 187
Other(58) 110
Net cash provided by financing activities1,303
 3,919
DISCONTINUED OPERATIONS   
Operating activities245
 168
Investing activities(82) (359)
Changes in cash included in current assets held for sale(4) 12
Net increase (decrease) in cash and cash equivalents of discontinued operations159
 (179)
Increase (decrease) in cash and cash equivalents6
 (123)
Cash and cash equivalents, beginning of period463
 581
Cash and cash equivalents, end of period$469
 $458
 Six Months Ended
June 30,
 2020 2019*
OPERATING ACTIVITIES:   
Net income (loss)$(292) $2,327
Reconciliation of net income (loss) to net cash provided by operating activities:   
Depreciation, depletion and amortization1,803
 1,559
Deferred income taxes125
 138
Inventory valuation adjustments137
 (97)
Non-cash compensation expense63
 58
Impairment losses1,329
 50
Losses on extinguishments of debt62
 18
Distributions on unvested awards(21) (18)
Equity in earnings of unconsolidated affiliates(78) (142)
Distributions from unconsolidated affiliates125
 170
Other non-cash(53) 44
Net change in operating assets and liabilities, net of effects of acquisitions(65) (213)
Net cash provided by operating activities3,135
 3,894
INVESTING ACTIVITIES:   
Cash proceeds from sale of noncontrolling interest in subsidiary—
 93
Cash paid for all other acquisitions, net of cash received—
 (7)
Capital expenditures, excluding allowance for equity funds used during construction(2,892) (2,818)
Contributions in aid of construction costs47
 41
Contributions to unconsolidated affiliates(16) (254)
Distributions from unconsolidated affiliates in excess of cumulative earnings97
 21
Proceeds from the sale of other assets6
 22
Other(5) (40)
Net cash used in investing activities(2,763) (2,942)
FINANCING ACTIVITIES:   
Proceeds from borrowings16,975
 16,463
Repayments of debt(16,769) (15,925)
Subsidiary units issued for cash1,580
 780
Capital contributions from noncontrolling interests178
 206
Distributions to partners(1,584) (1,549)
Distributions to noncontrolling interests(852) (813)
Debt issuance costs(50) (87)
Other, net14
 (1)
Net cash used in financing activities(508) (926)
Increase (decrease) in cash and cash equivalents(136) 26
Cash and cash equivalents, beginning of period291
 419
Cash and cash equivalents, end of period$155
 $445
*As adjusted. See Note 1.

ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)
(unaudited)
1.ORGANIZATION AND BASIS OF PRESENTATION
Organization
UnlessThe consolidated financial statements presented herein contain the context requires otherwise, references toresults of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries.“our” or “ET”). References to the “Parent Company” mean Energy Transfer Equity, L.P.LP on a stand-alone basis.
In April 2017, Energy Transfer Partners, L.P. and Sunoco LogisticsDecember 2019, we completed the acquisition of SemGroup. In connection with the transaction, a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidatedwholly-owned subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders received 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner wasET merged with and into ETP GP,SemGroup, with ETP GPSemGroup surviving the merger. During the first and second quarters of 2020, ET contributed SemGroup and its former subsidiaries to ETO through sale and contribution transactions (together, the “SemGroup Transaction”).
Substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ET’s subsidiaries.
Our financial statements reflect the following reportable segments:
•intrastate transportation and storage;
•interstate transportation and storage;
•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services;
•investment in Sunoco LP;
•investment in USAC; and
•corporate and other, including the following:
activities of the Parent Company; and
certain operations and investments that are not separately reflected as an indirect wholly-owned subsidiaryreportable segments.
Basis of ETE. BasedPresentation
The unaudited financial information included in this Form 10-Q has been prepared on the number of Energy Transfer Partners, L.P. common units outstanding atsame basis as the closingaudited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020. In the opinion of the merger, Sunoco Logistics issued approximately 832 million Sunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. Class E units, Class G units, Class I units and Class K units at the effective timePartnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the merger were converted into an equal numberfinancial position and the results of newly created classes of Sunoco Logistics units,operations for such interim periods in accordance with the same rights, preferences, privileges, dutiesGAAP. All intercompany items and obligations as such classes of Energy Transfer Partners, L.P. units had immediately priortransactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the closingrules and regulations of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.
Prior to the Sunoco Logistics Merger, ETE owned 18.4 million Energy Transfer Partners, L.P. common units (representing 3.3% of the total outstanding common units), 81 million Energy Transfer Partners, L.P. Class H units and 100 Energy Transfer Partners, L.P. Class I units. In connection with the Sunoco Logistics Merger, the Class H units were cancelled, and ETE now owns 27.5 million ETP common units (representing 2.5% of the total outstanding common units) and 100 ETP Class I units. The ETP Class I units have the same rights, privileges, duties and obligations as those historically associated with the Class I units prior to the Sunoco Logistics Merger.
At the time of the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. For purposes of maintaining clarity, the following references are used herein:
References to “ETLP” refer to the entity named Energy Transfer, LP subsequent to the close of the merger;
References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and
References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.SEC.
The consolidated financial statements of ETEET presented herein include the results of operations of:
the Parent Company;
our controlled subsidiaries, subsidiary, ETO;
ETP and Sunoco LP;
consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that ownGP, the general partner interestsof ETO, and IDR interests inEnergy Transfer Partners, L.L.C., the general partner of ETP GP; and Sunoco LP; and
our wholly-owned subsidiary, Lake Charles LNG.
Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

Business Operations
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 15 for stand-alone financial information apart from that of the consolidated partnership information included herein.
Our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
Basis of Presentation
The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements for the year ended December 31, 2016 included as Exhibit 99.1 to our Form 8-K filed on October 2, 2017. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliate. Additionally, there were other prior period amounts have also been reclassified to conform to the 2017current period presentation. Other than the reclassification of certain balances to assets and liabilities held for sale and certain revenues and expenses to discontinued operations, theseThese reclassifications had no impact on net income or total equity.
Change in Accounting Policy
Effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. Under the revised accounting policy, certain amounts of crude oil that are not available for sale have been reclassified from inventory to non-current assets. These crude oil barrels, which are owned by the Partnership’s crude oil acquisition and marketing business, include pipeline linefill and tank bottoms and are not considered to be available for sale because the volumes must be maintained in order to continue normal operation of the related pipelines or tanks and because there is no expectation of liquidation or sale of these volumes in the near term.
Under the previous accounting policy, all crude oil barrels were recorded as inventory under the weighted-average cost method. Under the revised accounting policy, barrels related to pipeline linefill and tank bottoms are accounted for as long-lived assets and reflected as non-current assets on the consolidated balance sheet. These crude oil barrels will be tested for impairment consistent with the Partnership’s existing accounting policy for impairments of long-lived assets. The Partnership’s management believes that the change in accounting policy is preferable as it more closely aligns the accounting policies across the consolidated entity, given that similar assets in the Partnership’s natural gas, NGLs and refined products businesses are accounted for as non-current assets. In addition, management believes that reflecting these crude oil barrels as non-current assets better represents the economic results of the Partnership’s crude oil acquisition and marketing business by reducing volatility resulting from market price adjustments to crude oil barrels that are not expected to be sold or liquidated in the near term.
The impact of this accounting policy change on the Partnership’s net income for the six months ended June 30, 2020 was $265 million, or $0.10 per limited partner unit. As a result of this change in accounting policy, the Partnership’s consolidated balance sheets for prior periods have been retrospectively adjusted as follows:
 December 31, 2019 December 31, 2018
 As Originally Reported Effect of Change As Adjusted As Originally Reported Effect of Change As Adjusted
Inventories$1,935
 $(403) $1,532
 $1,677
 $(305) $1,372
Total current assets7,867
 (403) 7,464
 6,750
 (305) 6,445
Other non-current assets, net1,075
 496
 1,571
 1,006
 472
 1,478
Total assets98,880
 93
 98,973
 88,246
 167
 88,413
Total partners’ capital21,827
 93
 21,920
 20,559
 167
 20,726

In addition, the Partnership’s consolidated statements of operations, comprehensive income and cash flows for prior periods have been retrospectively adjusted as follows:
 Year Ended December 31, Three Months Ended June 30, Six Months Ended June 30,
 2019 2018 2019 2019
As originally reported:       
Consolidated Statements of Operations and Comprehensive Income       
Cost of products sold$39,727
 $41,658
 $10,302
 $19,717
Operating income7,277
 5,348
 1,819
 3,746
Income from continuing operations before income tax expense (benefit)5,094
 3,634
 1,242
 2,548
Net income4,899
 3,365
 1,208
 2,388
Net income per limited partner unit1.37
 1.16
 0.33
 0.66
Comprehensive income4,930
 3,322
 1,209
 2,397
Comprehensive income attributable to partners3,623
 1,651
 879
 1,757
        
Consolidated Statements of Cash Flows       
Net income4,899
 3,365
 1,208
 2,388
Net change in operating assets and liabilities(518) 289
 67
 (274)
        
Effect of change:       
Consolidated Statements of Operations and Comprehensive Income       
Cost of products sold74
 (55) (1) 61
Operating income(74) 55
 1
 (61)
Income from continuing operations before income tax expense (benefit)(74) 55
 1
 (61)
Net income(74) 55
 1
 (61)
Net income per limited partner unit(0.03) 0.04
 —
 (0.02)
Comprehensive income(74) 55
 1
 (61)
Comprehensive income attributable to partners(74) 55
 1
 (61)
        
Consolidated Statements of Cash Flows       
Net income(74) 55
 1
 (61)
Net change in operating assets and liabilities74
 (55) (1) 61
        
As adjusted:       
Consolidated Statements of Operations and Comprehensive Income       
Cost of products sold39,801
 41,603
 10,301
 19,778
Operating income7,203
 5,403
 1,820
 3,685
Income from continuing operations before income tax expense (benefit)5,020
 3,689
 1,243
 2,487
Net income4,825
 3,420
 1,209
 2,327
Net income per limited partner unit1.34
 1.20
 0.33
 0.64
Comprehensive income4,856
 3,377
 1,210
 2,336
Comprehensive income attributable to partners3,549
 1,706
 880
 1,696
        
Consolidated Statements of Cash Flows       
Net income4,825
 3,420
 1,209
 2,327
Net change in operating assets and liabilities(444) 234
 66
 (213)


Use of Estimates
The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Subsidiary Common Unit Transactions
The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP or Sunoco LP (excluding transactions with the Parent Company) as capital transactions.
Recent Accounting Pronouncements
ASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method, which requires recognition, upon the date of initial application, of the cumulative effect of the retrospective application of the standard.

We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements.
We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of ETP’s reportable segments as well as the accounting for certain processing contracts in ETP’s midstream operations. We do not expect these changes in the accounting for noncash consideration or processing contracts to impact net income.
We are still evaluating the potential impact of the adoption of ASU 2014-09 to contributions in aid of construction costs (“CIAC”) arrangements and materiality of any related changes. While we do not expect any impacts to net income from the application of the standard to other transactions, we have not concluded whether the application of the standard to CIAC transactions could impact net income.
We have substantially completed a detailed review of revenue contracts representative of Sunoco LP’s business segments and their revenue streams; however, we continue to evaluate contract modifications and new contracts that have been or will be entered prior to the adoption date. As a result of the evaluation performed to date, we have determined that the timing and/or amount of revenue that Sunoco LP recognizes on certain contracts will be impacted by the adoption of the new standard; however, we are quantifying these impacts and cannot currently conclude whether or not they would be material to the financial statements.
We continue to assess the impact of the disclosure requirements under the new standard and are evaluating the manner in which we will disaggregate revenue into categories that show how economic factors affect the nature, timing and uncertainty of revenue and cash flows generated from contracts with customers. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us.
ASU 2016-02
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-09
OnEffective January 1, 2017,2020, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation(“ASU”) 2016-13 “Financial Instruments - Credit Losses (Topic 718)326) Measurement of Credit Losses on Financial Instruments.” ASU 2016-13 requires an entity to utilize a new impairment model known as the current expected credit loss (“ASU 2016-09”CECL”). The objective model to estimate its lifetime “expected credit loss” and record an allowance that, when deducted from the amortized cost basis of the updatefinancial asset, presents the net amount expected to be collected on the financial asset. The CECL model is expected to reduce complexityresult in accounting standards.more timely recognition of credit losses. The areasimpact of adoption was immaterial to the Partnership. However, due in large part to the global economic impacts of COVID-19, the Partnership and its subsidiaries recorded an aggregate $16 million of current expected credit losses for simplification in this update involve several aspectsthe six months ended June 30, 2020.
Goodwill
During the first quarter of 2020, due to the impacts of the accountingCOVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. We performed the interim impairment tests consistent with our approach for employee share-based payment transactions,annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $483 million related to our Arklatex and South Texas operations within the midstream segment, a goodwill impairment of $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and a goodwill impairment of $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations. No other impairments of the Partnership’s goodwill were identified.
In connection with aforementioned impairments, the Partnership determined the fair value of our reporting units using the income tax consequences, classification of awards as either equity or liabilities, and classificationapproach. The income approach is based on the statementpresent value of future cash flows.flows, which are derived from our long-term financial forecasts, and requires significant assumptions including, among others, revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The adoptionPartnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of this standard didthe assumptions could result in materially different calculations of fair value and determinations of whether or not have a material impactan impairment is indicated. Cash flow projections are derived from one-year budgeted amounts and three-year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur.
Of the $3.87 billion of goodwill on the Partnership’s consolidated financial statements and related disclosures.
ASU 2016-16
In October 2016,balance sheet as of June 30, 2020, approximately $1.2 billion is recorded in reporting units for which the FASB issued Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognizeestimated fair value exceeded the income tax consequences of an intra-entity transfer of an asset othercarrying value by less than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures.
ASU 2016-17
On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17, Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests

20% in the entity held through related partiesmost recent quantitative test. Management believes that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.
ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second stepall of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record$1.2 billion is at significant risk of impairment, if commodity prices and/or overall market demand remains low.
Changes in the carrying amount of goodwill impairmentwere as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. Sunoco LP early adopted ASC No. 2017-04 during its interim goodwill impairment test in the second quarter of 2017. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.follows:
ASU 2017-12
 Intrastate
Transportation
and Storage		 Interstate
Transportation and Storage		 Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total
Balance, December 31, 2019$10
 $226
 $483
 $693
 $1,397
 $1,555
 $619
 $184
 $5,167
Impaired—
 (183) (483) —
 —
 —
 (619) (40) (1,325)
Other—
 —
 —
 —
 —
 —
 —
 (7) (7)
Balance, March 31, 202010
 43
 —
 693
 1,397
 1,555
 —
 137
 3,835
Other—
 —
 —
 —
 —
 —
 —
 33
 33
Balance, June 30, 2020$10
 $43
 $—
 $693
 $1,397
 $1,555
 $—
 $170
 $3,868

In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

2.ACQUISITIONSCASH AND DIVESTURESCASH EQUIVALENTS
Rover Contribution Agreement
In July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.  The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.
Permian Express Partners
In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“PEP”), a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of ETP. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.
Sunoco LP Convenience Store Sale
On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for the sale of a portfolio of approximately 1,112 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company, to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion (the “7-Eleven

Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur within the fourth quarter of 2017 or early portion of the first quarter of 2018.
With the assistance of a third-party brokerage firm, Sunoco LP is continuing marketing efforts with respect to approximately 208 Stripes sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the 7-Eleven purchase agreement.
Sunoco LP Real Estate Sale
In January 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties will be sold through a sealed-bid sale. Of the 97 properties, 27 have been sold and an additional 14 are under contract to be sold. 31 are being sold to 7-Eleven and 10 are being sold in another transaction. The remaining 15 continue to be marketed by the third-party brokerage firm.
The assets under the asset purchase agreement, the 208 Stripes sites and the real estate assets subject to the portfolio optimization plan comprise the retail divestment presented as discontinued operations (“Retail Divestment”).
The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale.
The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:
 September 30, 2017 December 31, 2016
Carrying amount of assets classified as held for sale:   
Cash and cash equivalents$24
 $20
Inventories183
 188
Other current assets91
 83
Property, plant and equipment, net2,132
 2,185
Goodwill1,216
 1,568
Intangible assets, net499
 503
Other non-current assets, net2
 2
Total assets classified as held for sale in the Consolidated Balance Sheet$4,147
 $4,549
    
Carrying amount of liabilities classified as held for sale:   
Other current and non-current liabilities81
 68
Total liabilities classified as held for sale in the Consolidated Balance Sheet$81
 $68

The results of operations associated with discontinued operations are presented in the following table:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
REVENUES$2,312
 $1,970
 $6,580
 $5,474
        
COSTS AND EXPENSES       
Cost of products sold1,927
 1,585
 5,478
 4,445
Operating expenses236
 250
 727
 727
Depreciation, depletion and amortization5
 47
 68
 149
Selling, general and administrative57
 37
 122
 74
Total costs and expenses2,225
 1,919
 6,395
 5,395
OPERATING INCOME87
 51
 185
 79
Interest expense, net13
 7
 22
 22
Other, net38
 1
 367
 4
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)36
 43
 (204) 53
Income tax expense30
 31
 60
 29
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES$6
 $12
 $(264) $24
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE$—
 $—
 $(9) $—
In connection with the classification of those assets as held-for-sale, the related goodwill was tested for impairment based on the assumed proceeds from the sale of those assets, resulting in goodwill impairment charges of $320 million recognized in the three months ended June 30, 2017 and $44 million recognized in the three months ended September 30, 2017.
3. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. The Partnership’s consolidated balance sheets did not include any material amounts of restricted cash as of June 30, 2020 or December 31, 2019.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
Non-cash investingThe net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities wereis comprised as follows:
 Six Months Ended
June 30,
 2020 2019
Accounts receivable$2,084
 $(340)
Accounts receivable from related companies111
 (1)
Inventories(180) 28
Other current assets146
 30
Other non-current assets, net(226) (44)
Accounts payable(2,108) 199
Accounts payable to related companies(8) (49)
Accrued and other current liabilities(116) (89)
Other non-current liabilities42
 (87)
Derivative assets and liabilities, net190
 140
Net change in operating assets and liabilities, net of effects of acquisitions$(65) $(213)

 Nine Months Ended
September 30,
 2017 2016
NON-CASH INVESTING ACTIVITIES:   
Accrued capital expenditures$1,237
 $1,001
Losses from subsidiary common unit issuances, net(57) (3)
NON-CASH FINANCING ACTIVITIES:   
Contribution of property, plant and equipment from noncontrolling interest$988
 $—
Non-cash activities are as follows:

 Six Months Ended
June 30,
 2020 2019
NON-CASH INVESTING AND FINANCING ACTIVITIES:   
Accrued capital expenditures$742
 $714
Lease assets obtained in exchange for new lease liabilities125
 15
Distribution reinvestment62
 51

4. INVENTORIES
3.INVENTORIES
As further discussed in Note 1, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. As a result of this change in accounting policy, the Partnership’s inventory balance for the prior period has been retrospectively adjusted.
Inventories consisted of the following:
 June 30,
2020		 December 31,
2019
Natural gas, NGLs and refined products$774
 $833
Crude oil367
 251
Spare parts and other452
 448
Total inventories$1,593
 $1,532

 September 30, 2017 December 31, 2016
Natural gas and NGLs$609
 $699
Crude oil696
 683
Refined products413
 483
Other239
 238
Total inventories$1,957
 $2,103

ETP utilizesWe utilize commodity derivatives to manage price volatility associated with itsour natural gas inventories stored in our Bammel storage facility.inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in, first-out (“LIFO”) method.  As of June 30, 2020 and December 31, 2019, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $372 million and $229 million, respectively, and the inventory carrying value equaled or exceeded its replacement cost.  For the three and six months ended June 30, 2020 and 2019, the Partnership’s consolidated income statements did not include any material amounts of income from the liquidation of LIFO fuel inventory.
4.FAIR VALUE MEASURES
5. FAIR VALUE MEASURES
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of September 30, 2017 were $47.21 billion and $45.21 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations were $45.05 billion and $43.80 billion, respectively. The fair value of our consolidated debt obligations is Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities.
We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the ninesix months ended September June 30, 2017, no2020, 0 transfers were made between any levels within the fair value hierarchy.

The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of SeptemberJune 30, 20172020 and December 31, 20162019 based on inputs used to derive their fair values:
  Fair Value Measurements at
September 30, 2017		  Fair Value Measurements at
June 30, 2020
Fair Value Total Level 1 Level 2Fair Value Total Level 1 Level 2
Assets:          
Commodity derivatives:          
Natural Gas:          
Basis Swaps IFERC/NYMEX16
 16
 —
$112
 $112
 $—
Swing Swaps IFERC2
 —
 2
2
 —
 2
Fixed Swaps/Futures28
 28
 —
93
 93
 —
Forward Physical Swaps3
 —
 3
Forward Physical Contracts7
 —
 7
Power:          
Forwards11
 —
 11
21
 —
 21
Futures1
 1
 —
3
 3
 —
Options — Puts1
 1
 —
Natural Gas Liquids – Forwards/Swaps213
 213
 —
Refined Products — Futures4
 4
 —
Crude – Futures2
 2
 —
Options – Puts1
 1
 —
Options – Calls1
 1
 —
NGLs – Forwards/Swaps208
 208
 —
Refined Products – Futures4
 4
 —
Crude – Forwards/Swaps3
 3
 —
Total commodity derivatives281
 265
 16
455
 425
 30
Other non-current assets29
 19
 10
Total assets$281
 $265
 $16
$484
 $444
 $40
Liabilities:          
Interest rate derivatives$(210) $—
 $(210)$(577) $—
 $(577)
Commodity derivatives:          
Natural Gas:          
Basis Swaps IFERC/NYMEX(22) (22) —
(83) (83) —
Swing Swaps IFERC(3) (1) (2)(5) —
 (5)
Fixed Swaps/Futures(22) (22) —
(117) (117) —
Forward Physical Swaps(1) —
 (1)
Forward Physical Contracts(1) —
 (1)
Power:          
Forwards(9) —
 (9)(17) —
 (17)
Futures(1) (1) —
(3) (3) —
Natural Gas Liquids – Forwards/Swaps(261) (261) —
Refined Products — Futures(3) (3) —
Crude — Futures(1) (1) —
NGLs – Forwards/Swaps(218) (218) —
Refined Products – Futures(21) (21) —
Crude – Forwards/Swaps(1) (1) —
Total commodity derivatives(323) (311) (12)(466) (443) (23)
Total liabilities$(533) $(311) $(222)$(1,043) $(443) $(600)

   Fair Value Measurements at
December 31, 2019
 Fair Value Total Level 1 Level 2
Assets:     
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX$17
 $17
 $—
Swing Swaps IFERC1
 —
 1
Fixed Swaps/Futures65
 65
 —
Forward Physical Contracts3
 —
 3
Power:     
Forwards11
 —
 11
Futures4
 4
 —
Options – Puts1
 1
 —
Options – Calls1
 1
 —
NGLs – Forwards/Swaps260
 260
 —
Refined Products – Futures8
 8
 —
Crude – Forwards/Swaps13
 13
 —
Total commodity derivatives384
 369
 15
Other non-current assets31
 20
 11
Total assets$415
 $389
 $26
Liabilities:     
Interest rate derivatives$(399) $—
 $(399)
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX(49) (49) —
Swing Swaps IFERC(1) —
 (1)
Fixed Swaps/Futures(43) (43) —
Power:  

 

Forwards(5) —
 (5)
Futures(3) (3) —
NGLs – Forwards/Swaps(278) (278) —
Refined Products – Futures(10) (10) —
Total commodity derivatives(389) (383) (6)
Total liabilities$(788) $(383) $(405)

   Fair Value Measurements at
December 31, 2016
 Fair Value Total Level 1 Level 2 Level 3
Assets:       
Natural Gas:       
Basis Swaps IFERC/NYMEX14
 14
 —
 —
Swing Swaps IFERC2
 —
 2
 —
Fixed Swaps/Futures96
 96
 —
 —
Forward Physical Contracts1
 —
 1
 —
Power:       
Forwards4
 —
 4
 —
Futures1
 1
 —
 —
Options — Calls1
 1
 —
 —
Natural Gas Liquids — Forwards/Swaps233
 233
 —
 —
Refined Products — Futures2
 2
 —
 —
Crude - Futures9
 9
 —
 —
Total commodity derivatives363
 356
 7
 —
Total assets$363
 $356
 $7
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) —
 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids — Forwards/Swaps(273) (273) —
 —
Refined Products — Futures(23) (23) —
 —
Crude - Futures(13) (13) —
 —
Total commodity derivatives(478) (470) (8) —
Total liabilities$(672) $(470) $(201) $(1)
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of June 30, 2020 were $52.99 billion and $51.29 billion, respectively. As of December 31, 2019, the aggregate fair value and carrying amount of our consolidated debt obligations were $54.79 billion and $51.05 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities.

6. NET INCOME PER LIMITED PARTNER UNIT
5.NET INCOME (LOSS) PER LIMITED PARTNER UNIT
A reconciliation of income and weighted average units used in computing basic and diluted income (loss) per unit is as follows:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2020 2019* 2020 2019*
Net income (loss)$672
 $1,209
 $(292) $2,327
Less: Net income attributable to noncontrolling interests306
 317
 185
 614
Less: Net income attributable to redeemable noncontrolling interests13
 13
 25
 26
Net income (loss), net of noncontrolling interests353
 879
 (502) 1,687
Less: General Partner’s interest in income (loss)—
 1
 (1) 2
Income (loss) available to Limited Partners$353
 $878
 $(501) $1,685
Basic Income (Loss) per Limited Partner Unit:       
Weighted average limited partner units2,694.9
 2,621.2
 2,693.3
 2,620.3
Basic income (loss) per Limited Partner unit$0.13
 $0.33
 $(0.19) $0.64
Diluted Income (Loss) per Limited Partner Unit:       
Income (loss) available to Limited Partners$353
 $878
 $(501) $1,685
Dilutive effect of equity-based compensation of subsidiaries (1)
—
 —
 —
 —
Diluted income (loss) available to Limited Partners$353
 $878
 $(501) $1,685
Weighted average limited partner units2,694.9
 2,621.2
 2,693.3
 2,620.3
Dilutive effect of unvested unit awards (1)
0.9
 9.8
 —
 9.8
Weighted average limited partner units, assuming dilutive effect of unvested unit awards2,695.8
 2,631.0
 2,693.3
 2,630.1
Diluted income (loss) from per Limited Partner unit$0.13
 $0.33
 $(0.19) $0.64

 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Income from continuing operations$798
 $29
 $1,475
 $777
Less: Income (loss) from continuing operations attributable to noncontrolling interest546
 (180) 763
 15
Income from continuing operations, net of noncontrolling interest252
 209
 712
 762
Less: General Partner’s interest in income1
 —
 2
 2
Less: Convertible Unitholders’ interest in income11
 2
 25
 3
Income from continuing operations available to Limited Partners$240
 $207
 $685
 $757
Basic Income from Continuing Operations per Limited Partner Unit:       
Weighted average limited partner units1,079.1
 1,045.5
 1,077.9
 1,045.0
Basic income from continuing operations per Limited Partner unit$0.22
 $0.20
 $0.64
 $0.72
Basic loss from discontinued operations per Limited Partner unit$0.00
 $0.00
 $(0.01) $0.00
Diluted Income from Continuing Operations per Limited Partner Unit:       
Income from continuing operations available to Limited Partners$240
 $207
 $685
 $757
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders10
 2
 25
 3
Diluted income from continuing operations available to Limited Partners$250
 $209
 $710
 $760
Weighted average limited partner units1,079.1
 1,045.5
 1,077.9
 1,045.0
Dilutive effect of unconverted unit awards and Convertible Units69.2
 55.2
 69.4
 26.3
Diluted weighted average limited partner units1,148.3
 1,100.7
 1,147.3
 1,071.3
Diluted income from continuing operations per Limited Partner unit$0.22
 $0.19
 $0.62
 $0.71
Diluted loss from discontinued operations per Limited Partner unit$0.00
 $0.00
 $(0.01) $0.00
*As adjusted. See Note 1.
(1) Dilutive effects are excluded from the calculation for periods where the impact would have been antidilutive.
7. DEBT OBLIGATIONS
6.DEBT OBLIGATIONS
Parent Company Indebtedness
The Parent Company’s indebtedness, includingET Term Loan Facility
On January 15, 2019, ET paid in full all outstanding borrowings under its senior notes, senior secured term loan agreement and thereafter terminated the term loan agreement. In connection with the termination of the term loan agreement, the collateral securing certain series of the Partnership’s outstanding senior secured revolving credit facility, is secured by allnotes was released in accordance with the terms of its and certain of its subsidiaries’ tangible and intangible assets.the applicable indentures governing such senior notes.
Energy Transfer Equity, L.P.Subsidiary Indebtedness
ETO January 2020 Senior Notes Offering and Redemption
In October 2017, ETE issued $1On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.

The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The balance is payable upon maturity. Interest on the senior notes is paid semi-annually.
ETE Term Loan Facility
On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof.
Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in ETP or (b) equity interests of any person which owns, directly or indirectly, IDRs in ETP, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.
Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility is not guaranteed by any of the Partnership’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.
On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.
In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.
Revolving Credit Facility
On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the Revolver Lenders have committed to provide advances up to an aggregate principal amount of $1.5 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of September 30, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $309 million.

Subsidiary Indebtedness
Sunoco LP Term Loan
Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of September 30, 2017, the balance on the term loan was $1.24 billion.
ETPETO’s 2.900% Senior Notes Redemption
In October 2017, ETP redeemed all of the outstanding $500 million aggregate principal amount of ETLP’s 6.50% senior notes due July 2021 and all of the outstanding $700 million aggregate principal amount of ETLP’s 5.50% senior notes due April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.
ETP Senior Notes Offering 
In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and2025, $1.50 billion aggregate principal amount of 5.40%the Partnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of ETO’s 5.000% Senior Notes due 2050 (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by ETO’s wholly-owned subsidiary, Sunoco Logistics Operations, on a senior notes due 2047. The $2.22 billion netunsecured basis.
Using proceeds from the offering were used to redeem all of the $500January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of ETLP’s 6.5% senior5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate

principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.
HFOTCO Long-Term Debt
In connection with the contribution transactions discussed in Note 2, HFOTCO became a wholly-owned subsidiary of ETO in February 2020. As of June 30, 2020, HFOTCO had $225 million outstanding of tax exempt notes due 2021,2050 (the “Ike Bonds”). The Ike Bonds are fully and unconditionally guaranteed by the Partnership, on a senior unsecured basis. The indentures under which the Ike Bonds were issued are subject to repay borrowings outstandingcustomary representations and warranties and affirmative and negative covenants, the majority of which are substantially similar to those found in ETO’s revolving credit facility, as further discussed below.
Credit Facilities and Commercial Paper
ETO Term Loan
ETO’s term loan credit agreement provides for a $2 billion three-year term loan credit facility (the “ETO Term Loan”). Borrowings under the Sunoco Logistics Credit Facility (described below)term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The ETO Term Loan is unsecured and is guaranteed by ETO’s subsidiary, Sunoco Logistics Operations.
As of June 30, 2020, the ETO Term Loan had $2 billion outstanding and was fully drawn. The senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal is payable upon maturity. Interestweighted average interest rate on the senior notes is paid semi-annually. The senior notes are guaranteed by ETP on a senior unsecured basistotal amount outstanding as long as it guarantees any of Sunoco Logistics Partners Operations L.P.’s other long-term debt. As a result of the parent guarantee, the senior notes will rank equally in right of payment with ETP’s existing and future senior debt, and senior in right of payment to any subordinated debt ETP may incur.  June 30, 2020 was 1.18%.
ETLPETO Five-Year Credit Facility
The ETLP Credit Facility allows for borrowings of up to $3.75 billion and matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of September 30, 2017, the ETLP Credit Facility had $2.06 billion of outstanding borrowings, all of which was commercial paper.
Sunoco Logistics Credit Facilities
ETP maintains the Sunoco Logistics $2.50 billion unsecuredETO’s revolving credit facility (the “Sunoco Logistics“ETO Five-Year Credit Facility”), which allows for unsecured borrowings up to $5.00 billion and matures in March 2020.on December 1, 2023. The Sunoco LogisticsETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $3.25$6.00 billion under certain conditions.
As of SeptemberJune 30, 2017,2020, the Sunoco LogisticsETO Five-Year Credit Facility had $35 million$3.01 billion of outstanding borrowings.borrowings, $1.11 billion of which was commercial paper. The amount available for future borrowings was $1.90 billion, after taking into account letters of credit of $86 million. The weighted average interest rate on the total amount outstanding as of June 30, 2020 was 1.34%.
In December 2016, Sunoco Logistics entered into an agreement for aETO 364-Day Facility
ETO’s 364-day maturityrevolving credit facility (“(the “ETO 364-Day Credit Facility”), due allows for unsecured borrowings up to mature$1.00 billion and matures on November 27, 2020. As of June 30, 2020, the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, theETO 364-Day Credit Facility was terminated and repaid in May 2017.had 0 outstanding borrowings.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit agreement,facility (the “Sunoco LP Credit Facility”), which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility.July 2023. As of SeptemberJune 30, 2017,2020, the Sunoco LP credit facilityCredit Facility had $644$158 million of outstanding borrowings and $9$8 million in standby letters of credit. As of June 30, 2020, Sunoco LP had $1.33 billion of availability under the Sunoco LP Credit Facility. The unused availabilityweighted average interest rate on the revolver total amount outstanding as of June 30, 2020 was 2.19%.
USAC Credit Facility
USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), with a further potential increase of $400 million, which matures in April 2023. As of June 30, 2020, the USAC Credit Facility had $448 million of outstanding borrowings and 0 outstanding letters of credit. As of June 30, 2020, USAC had $1.15 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $151 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of June 30, 2020 was 2.77%.
SemCAMS Credit Facilities
SemCAMS is party to a credit agreement providing for a C$350 million (US$257 million at SeptembertheJune 30, 2017 was $847 million.2020exchange rate) senior secured term loan facility, a C$525 million (US$385 million at the June 30, 2020exchange rate) senior secured revolving credit facility, and a C$300 million (US$220 million at theJune 30, 2020exchange rate) senior secured construction loan facility (the “KAPS Facility”). The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. SemCAMS may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$183 million at the June 30, 2020exchange rate), subject to receiving commitments

On October 16, 2017, Sunoco LP entered intofor such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.As of June 30, 2020, the Fifth Amendment to the Credit Agreement with the lenders party theretoSemCAMS senior secured term loan facility and Bank of America, N.A., in its capacity as a letter of credit issuer, as swing line lender, and as administrative agent. The Fifth Amendment amended the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestitures and the new fuel supply contracts, and (iv) modify the leverage ratio covenant.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billionsenior secured revolving credit facility provides substantially allhad $251 million and $92 million, respectively, of the remaining capital necessary to complete the projects.outstanding borrowings. As of SeptemberJune 30, 2017, $2.50 billion was 2020, the KAPS Facility had0outstanding under this credit facility.
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.borrowings.
Compliance with Our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective creditdebt agreements as of SeptemberJune 30, 2017.2020.
7.REDEEMABLE NONCONTROLLING INTERESTS
8. PREFERRED UNITSCertain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of June 30, 2020 included a balance of $477 million related to the USAC Preferred Units described below and a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. In addition, redeemable noncontrolling interests includes a balance of $258 million in SemCAMS preferred shares.
In January 2017, Energy Transfer Partners, L.P. repurchasedUSAC Preferred Units
As of June 30, 2020, USAC had 500,000 USAC Preferred Units issued and outstanding. The holders of these units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units will be convertible into USAC common units at the election of the holders beginning in 2021. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by April 2, 2023, USAC will have the option to redeem all or any portion of its 1.9 million outstandingthe USAC Preferred Units for cashcash. In addition, at any time on or after April 2, 2028, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and the Partnership may elect to pay up to 50% of such redemption amount in USAC common units.
SemCAMS Redeemable Preferred Stock
As of June 30, 2020, SemCAMS had 329,830 shares of cumulative preferred stock issued and outstanding. The preferred stock is redeemable at SemCAMS’s option subsequent to January 3, 2021 at a redemption price of C$1,100 (US$807 at the June 30, 2020 exchange rate) per share. The preferred stock is redeemable by the holder contingent upon a change of control or liquidation of SemCAMS. The preferred stock is convertible to SemCAMS common shares in the aggregate amountevent of $53 million.an initial public offering by SemCAMS. Dividends on the preferred stock may be paid in-kind through June 30, 2021.
8.EQUITY
9. EQUITY
ETE
The changeschange in ETE common units and ConvertibleET Common Units during the ninesix months ended SeptemberJune 30,2017 were 2020 was as follows:
Six Months Ended June 30, 2020
Number of Common Units, beginning of period2,689.6
Common Units issued in connection with the distribution reinvestment plan5.3
Common Units vested under equity incentive plans and other0.7
Number of Common Units, end of period2,695.6

 Number of Convertible Units Number of Common Units
Outstanding at December 31, 2016329.3
 1,046.9
Issuance of common units—
 32.2
Outstanding at September 30, 2017329.3
 1,079.1
ETEET Equity Distribution AgreementProgram
In March 2017, the Partnership entered into an equity distribution agreement relating to at-the-market offerings of its common units with an aggregate offering price up to $1 billion. There was no activityAs of June 30, 2020, there have been 0 sales of common units under the equity distribution agreements for the nine months endedSeptember 30, 2017.agreement.
Series A Convertible Preferred Units
As of September 30, 2017, the Partnership had 329.3 million Series A Convertible Preferred Units outstanding with a carrying value of $377 million.
ETE January 2017 Private Placement and ETP Unit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units for approximately $568 million.
ET Repurchase Program
During the ninesix months ended SeptemberJune 30, 2017, ETE2020, ET did not repurchase any ETEET common units under its current buyback program. As of SeptemberJune 30, 2017, $9362020, $911 million remained available to repurchase under the current program.

Subsidiary Equity TransactionsET Distribution Reinvestment Program
The Parent Company accounts forDuring the difference between the carrying amount of its investment in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP and Sunoco LP (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the ninesix months ended SeptemberJune 30, 2017, we recognized decreases in partners’ capital of $57 million.
ETP Common Unit Transaction
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion. During the nine months ended September 30, 2017, ETP received proceeds of $498 million, net of $5 million of commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan. During the nine months ended September 30, 2017,2020, distributions of $106$62 million were reinvested under the distribution reinvestment plan.
ETP August 2017 Units Offering
In August 2017, ETP issued 54program. As of June 30, 2020, a total of 23 million ETP common units remain available to be issued under the existing registration statement in an underwritten public offering. Net proceedsconnection with the distribution reinvestment program.
Subsidiary Equity Transactions
ETO Preferred Units
As of $997 million from the offering were used by ETP to repay amountsJune 30, 2020 and December 31, 2019, ETO’s outstanding underpreferred units included 950,000 ETO Series A Preferred Units, 550,000ETOSeries B Preferred Units, 18,000,000 ETO Series C Preferred Units, 17,800,000 ETO Series D Preferred Units and 32,000,000 ETO Series E Preferred Units. As of June 30, 2020, ETO’s outstanding preferred units also included 500,000 ETO Series F Preferred Units and 1,100,000 ETO Series G Preferred Units.
ETO Series F Preferred Units
On January 22, 2020, ETO issued 500,000 of its revolving credit facilities, to fund capital expenditures and for general partnership purposes.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49%6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interest in ETO, at a price to the public of $1,000 per unit. Distributions on the ETO Series F Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2025, at a rate equal to 6.750% per annum of the $1,000 liquidation preference. On and after May 15, 2025, the distribution rate on the ETO Series F Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.134% per annum. The ETO Series F Preferred Units are redeemable at ETO’s option on or after May 15, 2025 at a redemption price of $1,000 per ETO Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
ETO Series G Preferred Units
On January 22, 2020, ETO issued 1,100,000 of its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75%7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interest in eachETO, at a price to the public of Dakota Access$1,000 per unit. Distributions on the ETO Series G Preferred Units are cumulative from and ETCO. The remaining 25%including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. In July 2017, ETP contributedyear, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a portion of its ownership interest in Dakota Access and ETCOrate equal to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all7.125% per annum of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all$1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the ETO Series G Preferred Units will equal a percentage of the economic interests$1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of PennTex,5.306% per annum. The ETO Series G Preferred Units are redeemable at ETO’s option on or after May 15, 2030 at a redemption price of $1,000 per ETO Series G Preferred Unit, plus an amount equal to all accumulated and PennTex common units are no longer publicly traded or listed onunpaid distributions thereon to, but excluding, the NASDAQ.date of redemption.
Sunoco LP Common Unit TransactionsEquity Distribution Program
DuringFor the ninesix months ended SeptemberJune 30, 2017,2020, Sunoco LP received net proceeds of $33 million from the issuance of 1.3 million Sunoco LP commonissued 0 additional units pursuant tounder its at-the-market equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes.program. As of SeptemberJune 30, 2017,2020, $295 million of Sunoco LP’sLP common units remained available to be issued under the currently effective equity distribution agreement.
Sunoco LP Series A Preferred UnitsUSAC Distribution Reinvestment Program
On MarchDuring the six months ended June 30, 2017,2020, distributions of $0.9 million were reinvested under the Partnership purchased Sunoco LP’s 12.0 million series A preferred units representing limited partner interestsUSAC distribution reinvestment program resulting in Sunoco LP in a private placement transaction for an aggregate purchase pricethe issuance of $300 million. The distribution rate of Sunoco LP Series A Preferred Units is 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference.

approximately 96,592 USAC common units.
Parent Company QuarterlyCash Distributions
Distributions declared and/or paid subsequent to December 31, 2019 were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2019 February 7, 2020 February 19, 2020 $0.3050
March 31, 2020 May 7, 2020 May 19, 2020 0.3050
June 30, 2020 August 7, 2020 August 19, 2020 0.3050


The Parent Company’s distribution on its common units with respect to the quarter ended March 31, 2020 was declared on March 31, 2020 and accrued as of Availablethat date.  For the three months ended June 30, 2020, the consolidated statement of equity reflects distributions to common unitholders for two quarters.  For the three months ended June 30, 2020, the amount reflected for distributions to common unitholders in the consolidated statements of equity reflects only the reinvestment of distributions paid in May 2020.
ETO Cash Distributions
Following are distributionsDistributions declared and/or paid by usETO to its preferred unitholders subsequent to December 31, 2016:2019 were as follows:
Period Ended Record Date Payment Date 
Series A (1)
 
Series B (1)
 Series C Series D Series E 
Series F (2)
 
Series G (2)
December 31, 2019 February 3, 2020 February 18, 2020 $31.25
 $33.125
 $0.4609
 $0.4766
 $0.4750
 $—
 $—
March 31, 2020 May 1, 2020 May 15, 2020 —
 —
 0.4609
 0.4766
 0.4750
 21.19
 22.36
June 30, 2020 August 3, 2020 August 17, 2020 31.25
 33.125
 0.4609
 0.4766
 0.4750
 —
 —

Quarter Ended Record Date Payment Date Rate
December 31, 2016 (1) February 7, 2017 February 21, 2017 $0.2850
March 31, 2017 (1) May 10, 2017 May 19, 2017 0.2850
June 30, 2017 (1)
 August 7, 2017 August 21, 2017 $0.2850
September 30, 2017 (1)
 November 7, 2017 November 20, 2017 0.2950
(1)    ETOSeries A Preferred Unit and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.
(1)(2) 
Certain common unitholders elected
ETO Series F and G Preferred Unit distributions related to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for athe period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions2020 represent a prorated initial distribution. Distributions are paid on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit.semi-annual basis.
Our distributions declared with respect to our Convertible Units subsequent to December 31, 2016 were as follows:
Quarter Ended          Record Date Payment Date  Rate
December 31, 2016 February 7, 2017 February 21, 2017 $0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100
ETP Quarterly Distributions of Available Cash
Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the ETP’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreement prior to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as "available cash" in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP's business. ETP will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
For the quarter ended December 31, 2016, Energy Transfer Partners, L.P. and Sunoco Logistics paid distributions on February 14, 2017 of $0.7033 and $0.52, respectively, per common unit.
Following are distributions declared and/or paid by ETP subsequent to the Sunoco Logistics Merger:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 15, 2017 $0.5350
June 30, 2017 August 7, 2017 August 14, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650

ETE has agreed to relinquish its right to the following amounts of incentive distributions from ETP in future periods:
  Total Year
2017 (remainder) $173
2018 153
2019 128
Each year beyond 2019 33
Sunoco LP QuarterlyCash Distributions of Available Cash
Following are distributionsDistributions declared and/or paid by Sunoco LP to its common unitholders subsequent to December 31, 2016:2019 were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2019 February 7, 2020 February 19, 2020 $0.8255
March 31, 2020 May 7, 2020 May 19, 2020 0.8255
June 30, 2020 August 7, 2020 August 19, 2020 0.8255

Quarter Ended Record Date Payment Date Rate
December 31, 2016 February 13, 2017 February 21, 2017 $0.8255
March 31, 2017 May 9, 2017 May 16, 2017 0.8255
June 30, 2017 August 7, 2017 August 15, 2017 0.8255
September 30, 2017 November 7, 2017 November 14, 2017 0.8255
USAC Cash Distributions
Distributions declared and/or paid by USAC to its common unitholders subsequent to December 31, 2019 were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2019 January 27, 2020 February 7, 2020 $0.5250
March 31, 2020 April 27, 2020 May 8, 2020 0.5250
June 30, 2020 July 31, 2020 August 10, 2020 0.5250

Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
 June 30,
2020		 December 31,
2019
Available-for-sale securities$13
 $13
Foreign currency translation adjustment(32) 2
Actuarial loss related to pensions and other postretirement benefits(14) (25)
Investments in unconsolidated affiliates, net(17) (1)
Total AOCI, net of tax(50) (11)
Amounts attributable to noncontrolling interest29
 —
Total AOCI included in partners’ capital, net of tax$(21) $(11)

 September 30, 2017 December 31, 2016
Available-for-sale securities$7
 $2
Foreign currency translation adjustment(5) (5)
Actuarial gain related to pensions and other postretirement benefits9
 7
Investments in unconsolidated affiliates, net3
 4
Subtotal14
 8
Amounts attributable to noncontrolling interest(14) (8)
Total AOCI, net of tax$—
 $—

9.INCOME TAXES
The Partnership’s effective tax rate differs from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level.
10.INCOME TAXESREGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
ForFERC Proceedings
By Order issued January 16, 2019, the nine months ended September 30, 2017, the Partnership’s income tax expense included the impactFERC initiated a review of a one-time adjustmentPanhandle’s existing rates pursuant to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $68 million during the periods presented. The remainderSection 5 of the increaseNatural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the Order dated October 1, 2019.  A hearing in the effective income tax rate was primarily due to higher nondeductible expenses among the Partnership’s consolidated corporate subsidiaries. In addition,combined proceedings is scheduled for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resultedAugust 2020, with an initial decision expected in a change in tax status for one of the subsidiaries. For the three and nine months ended September 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.
11. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
Contingent Residual Support Agreement – AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETLP (formerly Energy Transfer Partners, L.P.) agreed to provide contingent residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchasers. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETLP under the contingent residual support agreement. In February 2017, AmeriGas repurchased a portion of its 7.00% senior notes. The remaining outstanding 7.00% senior notes were repurchased in May 2017, and ETLP no longer provides contingent residual support for any AmeriGas notes.

FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.early 2021.
Commitments
In the normal course of our business, we purchase, processETO purchases, processes and sellsells natural gas pursuant to long-term contracts and we enterenters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believeETO believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on ourits financial position or results of operations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2047.  The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Rental expense$42
 $31
 $106
 $94
Less: Sublease rental income(6) (6) (19) (18)
Rental expense, net$36
 $25
 $87
 $76
Certain of our subsidiaries’ETO’s joint venture agreements require that theyETO fund theirits proportionate sharesshare of capital contributions to theirits unconsolidated affiliates. Such contributions will depend upon theirthe unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2020 2019 2020 2019
ROW expense$10
 $6
 $19
 $12

PES Refinery Fire and Bankruptcy
We previously owned an approximately 7.4% indirect non-operating interest in PES, which owned a former refinery in Philadelphia. In addition, the Partnership previously provided logistics services to PES under commercial contracts and Sunoco LP previously purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex.
On July 21, 2019, PES Holdings, LLC and seven of its subsidiaries (collectively, the “Debtors”) filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have also defaulted on a $75 million note payable to a subsidiary of the Partnership. In June 2020, the Partnership received $12 million from PES on the note payable and recorded a reserve for the remaining $63 million note balance.
In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of June 30, 2020, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such costs, and these liabilities are included in the total environmental liabilities discussed below under “Environmental Remediation.” It may be necessary for the Partnership to record additional environmental remediation liabilities in the future depending upon the use of such property by the buyer; however, management is not currently able to estimate such additional liabilities.
PES has rejected certain of the Partnership’s commercial contracts pursuant to Section 365 of the Bankruptcy Code; however, the impact of the bankruptcy on the Partnership’s commercial contracts and related revenue loss (temporary or permanent) is unknown at this time. In addition, Sunoco LP has been successful at acquiring alternative supplies to replace fuel volume lost from PES and does not anticipate any material impact to its business going forward.

Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
Dakota Access Pipeline
On July 25,27, 2016, the U.S.Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia challenging permits issued by the United States Army Corps of Engineers (“USACE”) issued permits topermitting Dakota Access, consistent with environmental and historic preservation statutes for the pipelineLLC (“Dakota Access”) to make two crossings of the Missouri River in North Dakota, including a crossing ofcross the Missouri River at Lake Oahe. After significant delay,Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE also issued easements to allowallowing the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the U.S. District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of theRiver. Dakota Access pipeline across those waterways and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency TRO to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the temporary restraining order (“TRO”) request moot.
After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.

The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion in the U.S. District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.
In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened in(collectively with SRST and CRST, the lawsuit in“Tribes”). Plaintiffs and Defendants filed cross motions for summary judgment. On March 25, 2020, the Court remanded the case back to the USACE for preparation of an Environment Impact Statement. On July 6, 2020, the Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 2016, moved5, 2020. Dakota Access and USACE have filed notices of appeal with the United States Court of Appeals for the District of Columbia (“Court of Appeals”) with respect to the Court’s ruling related to the preparation of an Environmental Impact Statement and also filed motions for a preliminary injunction and TRO to block operationstay of the pipeline. These motions raised, forCourt’s July 6, 2020 Order. On July 14, 2020, the first time, claims based onCourt of Appeals administratively stayed the religious rightsCourt’s July 6 Order and ordered further briefing with respect to the motion to stay. On August 5, 2020, the Court of Appeals granted a stay of the Tribe.portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil. The district courtCourt of Appeals also denied a stay of the TRO and preliminary injunction,March 25 Order and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.
The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes have filed related lawsuits to prevent constructionremaining portion of the July 6 Order vacating the easement. As a result, no court order stops Dakota Access pipeline project. These lawsuits have been consolidated intofrom continuing to operate the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four tribes.
On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment.Pipeline. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concludedAugust 5 Order contemplates that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its priorwill make a determination under certain of these statutes.its regulations and procedures whether vacating the easement requires oil to stop flowing. The Order also contemplates further proceedings in the District Court, orderedand it expedites the appeal with briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete this additional workconclude by April 2018. The Court has stayed consideration of any other claims until it fully resolves the remaining issues relating to its remand order.September 30, 2020.
While we believe that the pending lawsuits are unlikely to block operation of the pipeline, we cannot assure this outcome. WeEnergy Transfer cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.project, but expects after the law and complete record are fully considered, the issues in this litigation will be resolved in a manner that will allow the pipeline to continue to operate.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’sLLC’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal (CMB) and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells.wells, however, Lone Star is still quantifying the extent of its incurred and ongoing damages and has orobtained, and will be seekingcontinue to seek, reimbursement for these losses.
MTBE Litigation
ETC Sunoco Inc. and/orHoldings LLC and Sunoco Inc. (R&M), along with other refiners, manufacturers and sellers of gasoline,LLC (collectively, “Sunoco”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, typicallystate-level governmental authorities,entities, assert product liability, claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices.practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of SeptemberJune 30, 2017,2020, Sunoco Inc. is a defendant in six5 cases, including casesone case each initiated by the States of New Jersey, Vermont, Pennsylvania,Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two others by the Commonwealth of Puerto Rico with theRico. The more recent Puerto Rico action beingis a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court.
Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement withThe actions brought by the State of New Jersey. The court approved the Judicial Consent Order on October 10, 2017.Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals L.P. (“SPMT”).

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Regency Merger Litigation
Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB,related to the Regency-ETO merger (the “Regency Merger”) in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP LP;LP, Regency GP LLC; ETE, ETP,LLC, ET, ETO, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”).directors.
The Regency Merger litigationLitigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith.agreement. On March 29, 2016, the Delaware Court of Chancery granted the defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017,Plaintiff appealed, and the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff then filed an Amended Verified Class Action Complaint.Complaint, which defendants moved to dismiss. The Court of Chancery granted in part and denied in part the motions to dismiss, dismissing the claims against all defendants other than Regency Merger Litigation Defendants then filed Motions to Dismiss the Amended ComplaintGP LP and Regency GP LLC (the “Regency Defendants”). The Court of Chancery later granted Plaintiff’s unopposed motion for class certification. Trial was held on December 10-16, 2019, and a Motion to Stay Discoverypost-trial hearing was held on May 19, 2017. A hearing on these motions is currently set for January 9, 2018.6, 2020.
The Regency Merger Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Merger Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise approximately $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP intends to file a petition for review with the Texas Supreme Court.
Sunoco Logistics Merger Litigation
Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits have been voluntarily dismissed. The five remaining lawsuits have been consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs seek rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees.
The ETP-SXL Defendants cannot predict the outcome of the Sunoco Logistics Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing, nor can the ETP-SXL Defendants predict the amount of time and expense that will be required to resolve the Sunoco Logistics Merger Litigation. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Sunoco Logistics Merger.

it.
Litigation Filed By or Against Williams
OnIn April 6,and May 2016, Williams filed a complaint, Thethe Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP in the Delaware Court of Chancery(“Williams”) filed two lawsuits (the “First Delaware Williams“Williams Litigation”). Williams sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.
On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE andET, LE GP, and, addedin one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCGalleging that Defendants breached their obligations under the ET-Williams merger agreement (the “Second Delaware Williams Litigation”“Merger Agreement”). In general, Williams allegedalleges that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representationissuing the Partnership’s Series A Convertible Preferred Units (the “Issuance”), and warranty(c) making allegedly untrue representations and warranties in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions.Agreement.
ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.
After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware WMB LitigationDefendants and issued a declaratory judgment that ETEET could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.
Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based onnor the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Defendants breached an additional representationuntrue representations and warranty in the Merger Agreement.
Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.
warranties. On March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and OrderCourt’s ruling on the June 2016 trial and denied Williams’ motion for reargument on April 5, 2017. Astrial.
In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.based on the alleged breaches of the Merger Agreement listed above. Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) failing to use its reasonable best efforts to consummate the merger, (b) failing to provide material information to ET for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, and (d) breaching the Merger Agreement’s forum-selection clause.

In March 2020, the Court held argument on Defendant’s Motion for Summary Judgment and Williams’ Motion for Partial Summary Judgment. Those motions remain pending before the Court. Trial was set for August 31 to September 4, 2020, but has been continued to a later date because of the pandemic. Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.
Unitholder Litigation Relating to the IssuanceRover
In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery ofOn November 3, 2017, the State of Delaware (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joinedOhio and the consolidated action as an additional plaintiffOhio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio

EPA sought review from the Ohio Supreme Court, which the defendants opposed in briefs filed in February 2020. On April 25, 2016.22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for review. Briefing is underway and will conclude at the end of August 2020.
The IssuanceBayou Bridge
On January 11, 2018, environmental groups and a trade association filed suit against the USACE in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the Issuance breached various provisionsUSACE’s issuance of ETE’s limited partnership agreement.permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. ETO, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26, 2018.
On March 25, 2020, the Court granted summary judgment in favor of the USACE. Plaintiffs did not appeal by the deadline, and the case has concluded.
Revolution
On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries. On February 8, 2019, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Permit Hold on any requests for approvals/permits or permit amendments for any project in Pennsylvania pursuant to the state’s water laws. The Issuance Plaintiffs seek,Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board. On January 3, 2020, the Partnership entered into a Consent Order and Agreement with the PADEP in which, among other things, preliminarythe Permit Hold was lifted, the Partnership agreed to pay a $28.6 million civil penalty and permanent injunctive relief that (a) prevents ETE from making distributionsfund a $2 million community environmental project, and all related appeals were withdrawn.
The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Convertible UnitsIncident. The scope of these investigations is not further known at this time.
Chester County, Pennsylvania Investigation
In December 2018, the former Chester County District Attorney (“DA”) sent a letter to the Partnership stating that his office was investigating the Partnership and (b) invalidatesrelated entities for “potential crimes” related to the Mariner East pipelines.
Subsequently, the matter was submitted to an amendmentInvestigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the former DA sent a Notice of Intent to ETE’sthe Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the proscribed time period. To date, the Partnership is not aware of any further action with regard to this Notice.
In December 2019, the former DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges.
Delaware County, Pennsylvania Investigation
On March 11, 2019, the Delaware County District Attorney’s Office (“DA”) announced that the DA and the Pennsylvania Attorney General’s Office, at the request of the DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. On March 16, 2020, the Pennsylvania Attorney General Office served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. While the Partnership will cooperate with the subpoena, it intends to vigorously defend itself.
Recently Filed Litigation Involving Energy Transfer LP
Four purported unitholders of ET filed derivative actions against various past and current members of ET’s Board of Directors, LE GP, and ET, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of ET’s limited partnership agreement, that was adoptedtortious interference, abuse of control, and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania. They also seek damages and changes to ET’s corporate governance structure. See Bettiol v. LP GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); and King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.). Another purported unitholder of ET, Allegheny County Employees’ Retirement System (“ACERS”), individually and on March 8, 2016 as partbehalf of the Issuance.
On August 29, 2016, the Issuance Plaintiffsall others similarly situated, filed a consolidatedsuit

under the federal securities laws purportedly on behalf of a class, against ET and three of ET’s directors, Kelcy L. Warren, John W. McReynolds, and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants ET directors Marshall McCrea and Matthew Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.
Pennsylvania. The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is currently set for February 19-21, 2018.
The Issuance Defendantsdefendants cannot predict the outcome of the Issuance Litigationthese lawsuits or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendantsdefendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the Issuance Litigation. The Issuance Defendantsdefendants believe that the Issuance Litigation isclaims are without merit and intend to defend vigorously against it and any other actions challenging the Issuance.
Litigation filed by BP Products
On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.
SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.
On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued her initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.
On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.

contest them.
Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses.  For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage.  If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency.  As of SeptemberJune 30, 20172020 and December 31, 2016,2019, accruals of approximately $68$92 million and $77$120 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations.  As new information becomes available, our estimates may change.  The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
In December 2016, Sunoco Logistics received multiple Notice of Violations (“NOVs”) from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at its Marcus Hook Industrial Complex (“MHIC”) in July 2016. Sunoco Logistics also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to its tank inspection plan at MHIC.  These actions propose penalties in excess of $0.1 million, and ETP is currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.
The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of the Rover pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April to July, 2017. The Ohio EPA has proposed penalties of approximately $2.3 million in connection with the alleged violations and is seeking certain corrective actions. ETP is working with Ohio EPA to resolve the matter. The timing or outcome of this matter cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
In addition, on May 10, 2017,other legal proceedings exist that are considered reasonably possible to result in unfavorable outcomes.  For those where possible losses can be estimated, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessmentrange of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover has notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. On September 18, 2017, the FERC authorized Rover to resume HDD activities at the Tuscarawas River site and nine other river crossing sites. On October 20, 2017, the FERC authorized Rover to resume HDD activities at two additional sites.
On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover, among other things, to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover had 20 days to submit a corrective action plan and schedule for agency review. The order followed several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order and has already addressed many of the stormwater control issues. On August 9, 2017, WVDEP lifted the Cease and Desist requirement.
On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvaniapossible losses related to the Mariner East 2 project.  On August 1, 2017 the EHB lifted the order asthese contingent obligations is estimated to two drill locations.  On August 3, 2017, the EHB lifted the order asbe up to 14 additional locations.  The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”).  The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting.  On August 7, 2017 a final settlement was reached.  A stipulated order has been submitted to the EHB Judge with respect to the settlement.  The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation.  Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits.  Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.   
In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project.  Those

agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval.  SPLP is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.
No amounts$80 million; however, no accruals have been recorded in our Septemberas of June 30, 20172020 or December 31, 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.2019.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on theour results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
In February 2017, we received letters from the DOJ on behalf of EPA and Louisiana Department of Environmental Quality (“LDEQ”) notifying Sunoco Pipeline L.P. (“SPLP”)SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLPwhich allegedly occurred in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valleywhich allegedly occurred in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLPwhich allegedly occurred in January of 2015. In January 2019, a Consent Decree approved by all parties as well as an accompanying Complaint was filed

in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with the DOJ and LDEQ for the three releases. Subsequently, the court approved the Consent Decree and the penalty payment of $5.4 million was satisfied. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural resource damages with the Louisiana trustees related to the Caddo Parish, Louisiana release.
In October 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a notice of proposed safety order (the “Notice”) to SPMT, a wholly-owned subsidiary of ETO. The Notice alleged that conditions exist on certain pipeline facilities owned and operated by SPMT in Nederland, Texas that pose a pipeline integrity risk to public safety, property or the environment. The Notice also made preliminary findings of fact and proposed corrective measures. SPMT responded to the Notice by submitting a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and entered into a consent agreement with PHMSA resolving the issues in the Notice as of March 2019. SPMT is currently awaiting response from PHMSA regarding the approval status of the submitted Remedial Work Plan.
On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma.  The release occurred on the Noble to Douglas 8” pipeline in an area of this year, weexternal corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC.  The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure.  SPLP is negotiating a settlement agreement with the OCC for a lesser penalty. The OCC has accepted our counter offer in conjunction with a proposed consent order. The Consent Order will be presented to the DOJ, EPA and Louisiana DepartmentOCC at a final hearing, the date of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLPwhich is to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.be determined.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
•
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.
•
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
•
Legacy sites related to Sunoco that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.
•
Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of June 30, 2020, Sunoco had been named as a PRP at approximately 30 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Currently operating Sunoco, Inc. retail sites previously contributed to Sunoco LP in January 2016.
Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.

Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of September 30, 2017, Sunoco, Inc. had been named as a PRP at approximately 44 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
 June 30,
2020		 December 31,
2019
Current$43
 $46
Non-current261
 274
Total environmental liabilities$304
 $320

 September 30, 2017 December 31, 2016
Current$42
 $31
Non-current302
 318
Total environmental liabilities$344
 $349
In 2013, weWe have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the three months ended SeptemberJune 30, 20172020 and 2016,2019, the Partnership recorded $7 million and $12$9 million, respectively, of expenditures related to environmental cleanup programs. During the ninesix months ended SeptemberJune 30, 20172020 and 2016,2019, the Partnership recorded $22$15 million and $31$15 million, respectively.respectively, of expenditures related to environmental cleanup programs.
On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase AgreementOur pipeline operations are subject to sellregulation by the Toledo RefineryUnited States Department of Transportation under PHMSA, pursuant to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPAwhich PHMSA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relateestablished requirements relating to the time period that Sunoco, Inc. operateddesign, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the refinery. Specifically, EPAOffice of Pipeline Safety, has claimed thatpromulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or in conformance with their design,other effective means to assess the integrity of these regulated pipeline segments, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010the regulations require prompt action to address integrity issues raised by the assessment and 2011 to the EPA that failed to includeanalysis. Integrity testing and assessment of all of these assets will continue, and the information required bypotential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the regulations. EPA has proposed penalties in excesscontinued safe and reliable operation of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannotour pipelines; however, no estimate can be reasonably determinedmade at this time however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.the likely range of such expenditures.
Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’sthe Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations, but there is no assurance that such costs will not be material in the future.
11.REVENUE
Disaggregation of Revenue
The Partnership’s consolidated financial statements reflect eight reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes. Note 14 depicts the disaggregation of revenue by segment.
Contract Balances with Customers
The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.
The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.
The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but allow customers to apply such fees against services to be provided at a future point in time. These amounts are

12. DERIVATIVE ASSETS AND LIABILITIESreflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.
The following table summarizes the consolidated activity of our contract liabilities:
 Contract Liabilities
Balance, December 31, 2019$377
Additions413
Revenue recognized(405)
Balance, June 30, 2020$385
  
Balance, December 31, 2018$394
Additions300
Revenue recognized(315)
Balance, June 30, 2019$379
The balances of receivables from contracts with customers listed in the table below include both current trade receivables and long-term receivables, net of allowance for expected credit losses. The allowance for expected credit losses represents Sunoco LP's best estimate of the probable losses associated with potential customer defaults. Sunoco LP estimates the expected credit losses based on historical write-off experience by industry and current expectations of future credit losses.
The balances of Sunoco LP’s contract assets as of June 30, 2020 and December 31, 2019 were as follows:
 June 30,
2020		 December 31,
2019
Contract balances:   
Contract assets$128
 $117
Accounts receivable from contracts with customers263
 366

Costs to Obtain or Fulfill a Contract
Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g., sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in the future, and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the three months ended June 30, 2020 and 2019 was $5 million and $4 million, respectively. The amount of amortization expense that Sunoco LP recognized for the six months ended June 30, 2020 and 2019 was $10 million and $8 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.
12.DERIVATIVE ASSETS AND LIABILITIES
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, our subsidiarieswe utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price

result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in ETP’sour intrastate transportation and storage segment and operational gas sales on ETP’sin our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in ETP’sour midstream segment whereby itsour subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We use derivativesutilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in ETP’s NGL andthe price of refined products transportation and services segmentNGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing segment.sales. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement ETP’sour transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in ETP’sour all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in ETP’sour transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table details our outstanding commodity-related derivatives:
September 30, 2017 December 31, 2016June 30, 2020 December 31, 2019
Notional Volume Maturity Notional Volume MaturityNotional Volume Maturity Notional Volume Maturity
Mark-to-Market Derivatives        
(Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Basis Swaps IFERC/NYMEX (1)
(20,433) 2020-2024 (35,208) 2020-2024
Fixed Swaps/Futures1,297,500
 2017-2018 (682,500) 2017373
 2020-2021 1,483
 2020
Basis Swaps IFERC/NYMEX (1)
(15,810,000) 2017-2019 2,242,500
 2017
Options – Puts13,000,000
 2018 —
 ——
 — —
 —
Power (Megawatt):        
Forwards665,040
 2017-2018 391,880
 2017-20181,338,776
 2020-2029 3,213,450
 2020-2029
Futures(213,840) 2017-2018 109,564
 2017-2018204,090
 2020-2021 (353,527) 2020
Options — Puts(280,800) 2017-2018 (50,400) 2017
Options — Calls545,600
 2017-2018 186,400
 2017
Crude (Bbls):    
Futures(160,000) 2017 (617,000) 2017
Options – Puts(340,743) 2020 51,615
 2020
Options – Calls(1,268,532) 2020-2021 (2,704,330) 2020-2021
(Non-Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Basis Swaps IFERC/NYMEX67,500
 2017-2020 10,750,000
 2017-2018(27,713) 2020-2022 (18,923) 2020-2022
Swing Swaps IFERC91,897,500
 2017-2019 (5,662,500) 2017(35,590) 2020-2021 (9,265) 2020
Fixed Swaps/Futures(20,220,000) 2017-2019 (52,652,500) 2017-2019(10,708) 2020-2022 (3,085) 2020-2021
Forward Physical Contracts(140,937,993) 2017-2018 (22,492,489) 2017(23,980) 2020-2021 (13,364) 2020-2021
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps(8,744,200) 2017-2019 (5,786,627) 2017
Refined Products (Bbls) — Futures(1,947,000) 2017-2018 (3,144,000) 2017
Corn (Bushels) — Futures650,000
 2017-2018 1,580,000
 2017
NGLs (MBbls) – Forwards/Swaps(8,830) 2020 (1,300) 2020-2021
Refined Products (MBbls) – Futures(3,370) 2020-2022 (2,473) 2020-2021
Crude (MBbls) – Forwards/Swaps3,393
 2020 4,465
 2020
Corn (thousand bushels)—
 — (1,210) 2020
Fair Value Hedging Derivatives        
(Non-Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Basis Swaps IFERC/NYMEX(41,102,500) 2017 (36,370,000) 2017(43,235) 2020-2021 (31,780) 2020
Fixed Swaps/Futures(41,102,500) 2017 (36,370,000) 2017(43,235) 2020-2021 (31,780) 2020
Hedged Item — Inventory41,102,500
 2017 36,370,000
 2017
Hedged Item – Inventory43,235
 2020-2021 31,780
 2020
(1) 
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
    Notional Amount Outstanding
Term 
Type(1)
 September 30, 2017 December 31, 2016
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
Term 
Type(1)
 Notional Amount Outstanding
June 30,
2020		 December 31,
2019
July 2020(2)(3)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate $—
 $400
July 2021(2)
 Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400
 400
July 2022(2)
 Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400
 400
(1) 
Floating rates are based on 3-month LIBOR.
(2) 
Represents the effective date. These forward-starting swaps have a termterms of 30 years with a mandatory termination date the same as the effective date.
(3)
The July 2020 interest rate swaps were terminated in January 2020.
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern ETP’sour portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, ETPwe may at times require collateral under certain circumstances to mitigate credit risk as necessary. ETPWe also implements the use of industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, ETP utilizeswe utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
ETP’sOur counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, motor fuel distributors, municipalities, utilities and midstream companies. ETP’sOur overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could impact its counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
ETP hasWe have maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to ETPus on or about the settlement date for non-exchange traded derivatives, and ETP exchangeswe exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
  Fair Value of Derivative Instruments
  Asset Derivatives Liability Derivatives
  June 30,
2020		 December 31,
2019		 June 30,
2020		 December 31,
2019
Derivatives designated as hedging instruments:        
Commodity derivatives (margin deposits) $18
 $24
 $(22) $—
Derivatives not designated as hedging instruments:        
Commodity derivatives (margin deposits) 370
 319
 (367) (350)
Commodity derivatives 67
 41
 (77) (39)
Interest rate derivatives —
 —
 (577) (399)
  437
 360
 (1,021) (788)
Total derivatives $455
 $384
 $(1,043) $(788)
 Fair Value of Derivative Instruments
 Asset Derivatives Liability Derivatives
 September 30, 2017 December 31, 2016 September 30, 2017 December 31, 2016
Derivatives designated as hedging instruments:       
Commodity derivatives (margin deposits)$7
 $—
 $—
 $(4)
Derivatives not designated as hedging instruments:       
Commodity derivatives (margin deposits)$222
 $338
 $(262) $(416)
Commodity derivatives52
 25
 (61) (58)
Interest rate derivatives—
 —
 (210) (193)
Embedded derivatives in the ETP Preferred Units—
 —
 —
 (1)
 274
 363
 (533) (668)
Total derivatives$281
 $363
 $(533) $(672)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
 Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives
 Balance Sheet Location September 30, 2017 December 31, 2016 September 30, 2017 December 31, 2016 Balance Sheet Location June 30,
2020		 December 31,
2019		 June 30,
2020		 December 31,
2019
Derivatives without offsetting agreements Derivative assets (liabilities) $—
 $—
 $(210) $(194) Derivative liabilities $—
 $—
 $(577) $(399)
Derivatives in offsetting agreements:Derivatives in offsetting agreements:        Derivatives in offsetting agreements:        
OTC contracts Derivative assets (liabilities) 52
 25
 (61) (58) Derivative assets (liabilities) 67
 41
 (77) (39)
Broker cleared derivative contracts Other current assets 229
 338
 (262) (420) Other current assets (liabilities) 388
 343
 (389) (350)
Total gross derivativesTotal gross derivatives 281
 363
 (533) (672)Total gross derivatives 455
 384
 (1,043) (788)
Less offsetting agreements:        
Offsetting agreements:Offsetting agreements:        
Counterparty netting Derivative assets (liabilities) (10) (4) 10
 4
 Derivative assets (liabilities) (53) (18) 53
 18
Payments on margin deposit Other current assets (220) (338) 220
 338
Counterparty netting Other current assets (liabilities) (349) (318) 349
 318
Total net derivativesTotal net derivatives $51
 $21
 $(303) $(330)Total net derivatives $53
 $48
 $(641) $(452)
We disclose the non-exchange traded financial derivative instruments as price risk managementderivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-termnon-current depending on the anticipated settlement date.

The following tables summarizetable summarizes the location and amounts recognized in our consolidated statements of operations with respect to our derivative financial instruments:
 Location Amount of Gain (Loss) on Derivatives
   Three Months Ended
June 30,		 Six Months Ended
June 30,
   2020 2019 2020 2019
Derivatives not designated as hedging instruments:         
Commodity derivatives – TradingCost of products sold $(5) $(20) $11
 $(14)
Commodity derivatives – Non-tradingCost of products sold (96) (29) 97
 (41)
Interest rate derivativesLosses on interest rate derivatives (3) (122) (332) (196)
Total  $(104) $(171) $(224) $(251)

  
Location of Gain/(Loss)
Recognized in Income
on Derivatives
 Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
   Three Months Ended
September 30,		 Nine Months Ended
September 30,
    2017 2016 2017 2016
Derivatives in fair value hedging relationships (including hedged item):       
Commodity derivatives Cost of products sold $2
 $(9) $4
 $8
Total   $2
 $(9) $4
 $8
13.RELATED PARTY TRANSACTIONS
The Partnership has related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.
The following table summarizes the revenues from related companies on our consolidated statements of operations:
  
Location of Gain/(Loss)
Recognized in Income
on Derivatives
 Amount of Gain/(Loss) Recognized in Income on Derivatives
   Three Months Ended
September 30,		 Nine Months Ended
September 30,
    2017 2016 2017 2016
Derivatives not designated as hedging instruments:        
Commodity derivatives —Trading Cost of products sold $(5) $(7) $21
 $(24)
Commodity derivatives —Non-trading Cost of products sold (25) (16) (6) (61)
Interest rate derivatives Losses on interest rate derivatives (8) (28) (28) (179)
Embedded derivatives Other, net —
 8
 1
 4
Total   $(38) $(43) $(12) $(260)
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2020 2019 2020 2019
Revenues from related companies$142
 $136
 $275
 $245
The following table summarizes the accounts receivable from related companies on our consolidated balance sheets:
13. RELATED PARTY TRANSACTIONS
 June 30,
2020		 December 31,
2019
Accounts receivable from related companies:   
FGT$13
 $50
Phillips 669
 36
Traverse62
 42
Other56
 31
Total accounts receivable from related companies$140
 $159

InAs of June 2017, ETP acquired all of30, 2020 and December 31, 2019, accounts payable with unconsolidated affiliates in the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 9.
ETP previously had agreements with the Parent Company to provide services on its behalf and the behalf of other subsidiaries of the Parent Company, which included the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. These agreements expired in 2016.
In addition, ETE recorded sales with affiliates of $105Partnership’s consolidated balance sheets totaled $16 million and $49$31 million, during the three months ended September 30, 2017 and 2016, respectively, and $201 million and $175 million during the nine months ended September 30, 2017 and 2016, respectively.
14.    REPORTABLE SEGMENTS
14.REPORTABLE SEGMENTS
Our financial statementsreportable segments were reevaluated and currently reflect the following reportablesegments, which conduct their business segments:primarily in the United States:
Investment in ETP, including the consolidated operations of ETP;•intrastate transportation and storage;
Investment•interstate transportation and storage;
•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services;

•investment in Sunoco LP, includingLP;
•investment in USAC; and
•all other.
Consolidated revenues and expenses reflect the consolidated operationselimination of Sunoco LP;all material intercompany transactions.
InvestmentRevenues from our intrastate transportation and storage segment are primarily reflected in Lake Charles LNG, including the operations of Lake Charles LNG;natural gas sales and
Corporate gathering, transportation and Other, including the following:
activities of the Parent Company;other fees. Revenues from our interstate transportation and

the goodwill storage segment are primarily reflected in gathering, transportation and property, plantother fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
The Investmentgathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our investment in Sunoco LP segment reflects the resultsare primarily reflected in refined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales and gathering, transportation and other fees.
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of Sunoco LP and the legacy Sunoco, Inc. retail business for the periods presented.
segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair valueInventory adjustments (excludingthat are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market adjustments)reserves on inventory that is carried at last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Segment Adjusted EBITDA reflectsand consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the Partnership’s proportionate ownershipsame recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts for less than wholly owned subsidiaries based on 100%are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the subsidiaries’ resultsearnings or cash flows of operations.such affiliates.  The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.


The following tables present financial information by segment:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2020 2019 2020 2019
Revenues:       
Intrastate transportation and storage:       
Revenues from external customers$465
 $671
 $1,001
 $1,440
Intersegment revenues51
 94
 108
 181
 516
 765
 1,109
 1,621
Interstate transportation and storage:       
Revenues from external customers440
 487
 899
 979
Intersegment revenues5
 6
 10
 12
 445
 493
 909
 991
Midstream:       
Revenues from external customers391
 337
 892
 1,000
Intersegment revenues627
 861
 1,296
 1,916
 1,018
 1,198
 2,188
 2,916
NGL and refined products transportation and services:       
Revenues from external customers1,666
 2,356
 3,784
 5,069
Intersegment revenues453
 256
 1,050
 574
 2,119
 2,612
 4,834
 5,643
Crude oil transportation and services:       
Revenues from external customers1,811
 5,012
 6,024
 9,179
Intersegment revenues28
 34
 28
 53
 1,839
 5,046
 6,052
 9,232
Investment in Sunoco LP:       
Revenues from external customers2,043
 4,474
 5,303
 8,166
Intersegment revenues37
 1
 49
 1
 2,080
 4,475
 5,352
 8,167
Investment in USAC:       
Revenues from external customers166
 169
 342
 336
Intersegment revenues3
 5
 6
 9
 169
 174
 348
 345
All other:       
Revenues from external customers356
 371
 720
 829
Intersegment revenues136
 20
 285
 59
 492
 391
 1,005
 888
Eliminations(1,340) (1,277) (2,832) (2,805)
Total revenues$7,338
 $13,877
 $18,965
 $26,998
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Segment Adjusted EBITDA:       
Investment in ETP$1,744
 $1,390
 $4,757
 $4,172
Investment in Sunoco LP199
 189
 574
 512
Investment in Lake Charles LNG43
 45
 131
 133
Corporate and Other(3) (37) (25) (142)
Adjustments and Eliminations(74) (83) (211) (208)
Total1,909
 1,504
 5,226
 4,467
Depreciation, depletion and amortization(632) (548) (1,840) (1,596)
Interest expense, net(505) (474) (1,471) (1,336)
Losses on interest rate derivatives(8) (28) (28) (179)
Non-cash unit-based compensation expense(29) (23) (76) (46)
Unrealized gains (losses) on commodity risk management activities(76) (21) 22
 (105)
Losses on extinguishments of debt—
 —
 (25) —
Inventory valuation adjustments141
 35
 38
 203
Equity in earnings of unconsolidated affiliates92
 49
 228
 205
Adjusted EBITDA related to unconsolidated affiliates(205) (157) (554) (503)
Adjusted EBITDA related to discontinued operations(92) (93) (253) (220)
Impairment of investment in an unconsolidated affiliate—
 (308) —
 (308)
Other, net46
 4
 111
 44
Income (loss) before income tax benefit$641
 $(60) $1,378
 $626


 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2020 2019* 2020 2019*
Segment Adjusted EBITDA:       
Intrastate transportation and storage$187
 $290
 $427
 $542
Interstate transportation and storage403
 460
 807
 916
Midstream367
 412
 750
 794
NGL and refined products transportation and services674
 644
 1,337
 1,256
Crude oil transportation and services519
 752
 1,110
 1,496
Investment in Sunoco LP182
 152
 391
 305
Investment in USAC105
 105
 211
 206
All other1
 10
 40
 45
Adjusted EBITDA (consolidated)2,438
 2,825
 5,073
 5,560
Depreciation, depletion and amortization(936) (785) (1,803) (1,559)
Interest expense, net of interest capitalized(579) (578) (1,181) (1,168)
Impairment losses(4) —
 (1,329) (50)
Losses on interest rate derivatives(3) (122) (332) (196)
Non-cash compensation expense(41) (29) (63) (58)
Unrealized gains (losses) on commodity risk management activities(48) (23) 3
 26
Losses on extinguishments of debt—
 —
 (62) (18)
Inventory valuation adjustments (Sunoco LP)90
 4
 (137) 97
Adjusted EBITDA related to unconsolidated affiliates(157) (163) (311) (309)
Equity in earnings of unconsolidated affiliates85
 77
 78
 142
Other, net(74) 37
 (101) 20
Income (loss) before income tax expense771
 1,243
 (165) 2,487
Income tax expense(99) (34) (127) (160)
Net income (loss)$672
 $1,209
 $(292) $2,327
 September 30, 2017 December 31, 2016
Assets:   
Investment in ETP$77,011
 $70,191
Investment in Sunoco LP8,307
 8,701
Investment in Lake Charles LNG1,611
 1,508
Corporate and Other620
 711
Adjustments and Eliminations(2,169) (2,100)
Total assets$85,380
 $79,011

 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Revenues:       
Investment in ETP:       
Revenues from external customers$6,876
 $5,488
 $20,168
 $15,167
Intersegment revenues97
 43
 276
 134
 6,973
 5,531
 20,444
 15,301
Investment in Sunoco LP:       
Revenues from external customers2,549
 2,167
 7,321
 5,912
Intersegment revenues6
 —
 9
 6
 2,555
 2,167
 7,330
 5,918
Investment in Lake Charles LNG:       
Revenues from external customers49
 50
 148
 148
        
Adjustments and Eliminations(103) (43) (285) (140)
Total revenues$9,474
 $7,705
 $27,637
 $21,227
 June 30,
2020		 December 31, 2019*
Segment assets:   
Intrastate transportation and storage$6,972
 $6,648
Interstate transportation and storage17,413
 18,111
Midstream19,132
 20,332
NGL and refined products transportation and services21,803
 19,145
Crude oil transportation and services21,481
 22,933
Investment in Sunoco LP4,985
 5,438
Investment in USAC3,058
 3,730
All other1,063
 2,636
Total segment assets$95,907
 $98,973
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP, Sunoco LP and Lake Charles LNG.
Investment in ETP
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Intrastate Transportation and Storage$729
 $583
 $2,196
 $1,457
Interstate Transportation and Storage220
 231
 652
 714
Midstream665
 582
 1,863
 1,799
NGL and refined products transportation and services1,989
 1,397
 5,874
 4,014
Crude oil transportation and services2,714
 1,856
 7,749
 5,146
All Other656
 882
 2,110
 2,171
Total revenues6,973
 5,531
 20,444
 15,301
Less: Intersegment revenues97
 43
 276
 134
Revenues from external customers$6,876
 $5,488
 $20,168
 $15,167
The amounts included in ETP’s NGL and refined products transportation and services operation and the crude oil transportation and services operation have been retrospectively adjusted as a result of the Sunoco Logistics Merger.*As adjusted. See Note 1.


Investment in Sunoco LP
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Retail operations$88
 $80
 $247
 $241
Wholesale operations2,467
 2,087
 7,083
 5,677
Total revenues2,555
 2,167
 7,330
 5,918
Less: Intersegment revenues6
 —
 9
 6
Revenues from external customers$2,549
 $2,167
 $7,321
 $5,912
Investment in Lake Charles LNG
Lake Charles LNG’s revenues for all periods presented were related to LNG terminalling.

15. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION
Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:
BALANCE SHEETS
(unaudited)

 September 30, 2017 December 31, 2016
ASSETS   
Current assets:   
Cash and cash equivalents$—
 $2
Accounts receivable from related companies64
 55
Other current assets2
 —
Total current assets66
 57
Property, plant and equipment, net27
 36
Advances to and investments in unconsolidated affiliates6,031
 5,088
Intangible assets, net—
 1
Goodwill9
 9
Other non-current assets, net17
 10
Total assets$6,150
 $5,201
LIABILITIES AND PARTNERS’ CAPITAL   
Current liabilities:   
Accounts payable$—
 $1
Accounts payable to related companies—
 22
Interest payable79
 66
Accrued and other current liabilities3
 3
Total current liabilities82
 92
Long-term debt, less current maturities6,684
 6,358
Long-term notes payable – related companies574
 443
Other non-current liabilities2
 2
Commitments and contingencies
 
Partners’ capital:   
General Partner(3) (3)
Limited Partners:   
Common Unitholders(1,566) (1,871)
Series A Convertible Preferred Units377
 180
Total partners’ deficit(1,192) (1,694)
Total liabilities and equity$6,150
 $5,201


STATEMENTS OF OPERATIONS
(unaudited)
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)
$(3) $(75) $(25) $(156)
OTHER INCOME (EXPENSE):       
Interest expense, net(88) (81) (257) (244)
Equity in earnings of unconsolidated affiliates343
 367
 1,012
 1,166
Losses on extinguishments of debt—
 —
 (25) —
Other, net—
 (2) (2) (4)
NET INCOME252
 209
 703
 762
General Partner’s interest in net income1
 —
 2
 2
Convertible Unitholders’ interest in income11
 2
 25
 3
Limited Partners’ interest in net income$240
 $207
 $676
 $757

(1)
Prior periods include management fees paid by ETE to ETP, which management fees will no longer be paid subsequent to March 31, 2017.

STATEMENTS OF CASH FLOWS
(unaudited)
 Nine Months Ended
September 30,
 2017 2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES$620
 $718
CASH FLOWS FROM INVESTING ACTIVITIES:   
Contributions to unconsolidated affiliate(861) (70)
Capital expenditures(1) (15)
Contributions in aid of construction costs7
 —
Net cash used in investing activities(855) (85)
CASH FLOWS FROM FINANCING ACTIVITIES:   
Proceeds from borrowings2,116
 180
Principal payments on debt(1,795) (155)
Proceeds from affiliate131
 129
Distributions to partners(752) (780)
Units issued for cash568
 —
Debt issuance costs(35) —
Net cash provided by (used in) financing activities233
 (626)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(2) 7
CASH AND CASH EQUIVALENTS, beginning of period2
 1
CASH AND CASH EQUIVALENTS, end of period$—
 $8



ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts, except per unit data, are in millions)
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q10-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in Exhibit 99.1 to the Partnership’s Annual Report on Form 8-K10-K for the year ended December 31, 2019 filed with the SEC on October 2, 2017.February 21, 2020. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part I -– Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016.2019 filed with the SEC on February 21, 2020, “Part II - Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 11, 2020 and “Part II – Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q. Additional information on forward-looking statements is discussed below in “Forward-Looking Statements.”
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE”“ET” mean Energy Transfer Equity, L.P.LP and its consolidated subsidiaries, which include ETP, Sunoco LP and Lake Charles LNG.ETO. References to the “Parent Company” mean Energy Transfer Equity, L.P.LP on a stand-alone basis. See Note 1 to the consolidated financial statements for information related to recent name changes of our subsidiaries.
OVERVIEW
At September 30, 2017, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 27.5 million ETP common units, 2.3 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries.
Our reportable segments are as follows:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
RECENT DEVELOPMENTS
ETECOVID-19
In 2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to take extraordinary and wide-ranging actions to contain and combat the outbreak and spread of the virus, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions. As a provider of critical energy infrastructure, our business has been designated as a "critical infrastructure sector" and our employees as "essential critical infrastructure workers" pursuant to the Department of Homeland Security Guidance on Essential Critical Infrastructure Workforce(s). To date, our field operations have continued uninterrupted, and remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the magnitude or duration of current and potential future COVID-19 mitigation measures. As an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities and we will continue to operate in accordance with federal and state health guidelines and safety protocols. We have implemented several new policies and provided employee training to help maintain the health and safety of our workforce.
ET Contribution of SemGroup Assets to ETO
On December 5, 2019, ET completed the acquisition of SemGroup. During the first and second quarters of 2020, ET contributed former SemGroup assets to ETO through sale and contribution transactions.
ETO Series F and Series G Preferred Units Issuance
On January 22, 2020, ETO issued 500,000 of its Series F Preferred Units at a price of $1,000 per unit and 1,100,000 of its Series G Preferred Units at a price of $1,000 per unit. The net proceeds were used to repay amounts outstanding under ETO's revolving credit facility and for general partnership purposes.
ETO January 2020 Senior Notes Offering and Redemption
In October 2017, ETE issued $1On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.
ETE January 2017 Private Placement and Energy Transfer Partners, L.P. Unit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued Energy Transfer Partners, L.P. common units.
ETPETO’s 2.900% Senior Notes Redemption
In October 2017, ETP redeemed all of the outstanding $500 million aggregate principal amount of ETLP’s 6.50% senior notes due July 2021 and all of the outstanding $700 million aggregate principal amount of ETLP’s 5.50% senior notes due April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.
ETP Senior Notes Offering 
In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and2025, $1.50 billion aggregate principal amount of 5.40%the Partnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of ETO’s 5.000% Senior Notes due 2050 (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by ETO’s wholly-owned subsidiary, Sunoco Logistics Operations, on a senior notes due 2047. The $2.22 billion netunsecured basis.
Using proceeds from the offering were used to redeem all of the $500January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of ETLP’s 6.5% senior notes5.75% Senior Notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit FacilitySeptember 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and for general partnership purposes.Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.

ETP August 2017 Units OfferingLake Charles LNG
In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.
Rover Contribution Agreement
In July 2017, ETPOn March 30, 2020, Shell Royal Dutch Plc announced that it had entered into a contribution agreementwould not proceed with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9%proposed equity interest in the holding company that owns 65%Lake Charles LNG liquefaction project due to adverse market factors affecting Shell's business and its desire to preserve cash in light of the Rover pipeline (“Rover Holdco”)current environment. We intend to continue to develop the project, possibly in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The agreement with Blackstone required Blackstone to contribute, at closing, funds to reimburse ETP for its pro rata share ofproject is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.  The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.
Sunoco Logistics Merger
In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders received 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.
Sunoco LP Convenience Store Sale
On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for the sale of a portfolio of approximately 1,112 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company, to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur within the fourth quarter of 2017 or early portion of the first quarter of 2018.
With the assistance of a third-party brokerage firm, Sunoco LP is continuing marketing efforts with respect to approximately 208 Stripes sites located in certain West Texas, Oklahoma and New Mexico markets which were not included in the 7-Eleven purchase agreement. There can be no assurance of Sunoco LP’s success in selling the remaining company-operated retail assets, nor the price or terms of such sale, and even if a sale is consummated, Sunoco LP may remain contingently responsible for certain risks and obligationsinfrastructure related to the divested retailexisting regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets.
Sunoco LP Series A Preferred Units
On March 30, 2017, the Partnership purchased Sunoco LP’s 12,000,000 series A preferred units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units will be 10.00%, per annum, In light of the $25.00 liquidation preference per unit until March 30, 2022, at which pointexisting brownfield infrastructure and the distribution rate will become a floating rate of 8.00% plus three-month LIBORadvanced state of the Liquidation Preference.
Sunoco LP Real Estate Sale
In January 2017,development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan toproject based on market conditions, capital expenditure considerations and sell 97 real estate assets locatedour success in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties will be sold through a sealed-bid sale. Of the 97 properties, 27 have been sold and an additional 14 are under contract to be sold. 31 are being sold to 7-Eleven and 10 are being sold in another transaction. The remaining 15 continue to be marketedsecuring equity participation by the third-party brokerage firm.

Permian Express Partners
In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“PEP”), a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair valuethird parties as well as long-term LNG offtake commitments on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of ETP. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. In July 2017, ETP contributed a portion of its ownership interest in Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.satisfactory terms.
Quarterly Cash Distribution
In October 2017, ETEJuly 2020, ET announced its quarterly distribution of $0.295$0.3050 per unit ($1.181.22 annualized) on ETEET common units for the quarter ended SeptemberJune 30, 2017.2020.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Rate Regulation
Effective January 2018, the 2017 Tax and Jobs Act (the "Tax Act") changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes ("Revised Policy Statement") stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not "double recover" its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors' income tax costs. In light of the rehearing order, the impacts of the FERC's policy on the treatment of income taxes may have on the rates ETO can charge for the FERC regulated transportation services are unknown at this time.
The FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) on March 15, 2018, requesting comments on the effect of the Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to the FERC is whether, and if so how, the FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI were due on or before May 21, 2018.
In March 2019, following the decision of the D.C. Circuit in Emera Maine v. Federal Energy Regulatory Commission, the FERC issued a Notice of Inquiry regarding its policy for determining return on equity ("ROE"). The FERC specifically sought information and stakeholder views to help the FERC explore whether, and if so how, it should modify its policies concerning the determination of ROE to be used in designing jurisdictional rates charged by public utilities. The FERC also expressly sought comment on whether any changes to its policies concerning public utility ROEs should be applied to interstate natural gas and oil pipelines. Initial comments were due in June 2019, and reply comments were due in July 2019. The FERC has not taken any further action with respect to the Notice of Inquiry as of this time, and therefore we cannot predict what effect, if any, such development could have on our cost-of-service rates in the future.
By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing.  Panhandle filed a cost and revenue study on April 1, 2019. Panhandle filed a NGA Section 4 rate case on August 30, 2019.
Even without action on the 2017 Tax Law NOI or as contemplated in the Final Rule, the FERC or our shippers may challenge the cost of service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income

taxes, while other pipeline costs also will continue to affect the FERC’s determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, MEP and FEP, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or any final regulations that may result from the March 15, 2018 proposals. The revenues we receive from natural gas transportation services we provide pursuant to cost of service based rates may decrease in the future as a result of the ultimate outcome of the NOI, the Final Rule, and the Revised Policy Statement, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost of service rates, if any, will depend on a detailed review of all of ETO’s cost of service components and the outcomes of any challenges to our rates by the FERC or our shippers.
Pipeline Certification
The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or before July 25, 2018. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.
Interstate Common Carrier Regulation
The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index, or PPI. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize the FERC liquids index to change transportation rates annually every July 1. With respect to liquids and refined products pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on Page 700 of FERC Form No. 6. This information will be used by the FERC in its next five year review of the liquids pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. The FERC’s establishment of a just and reasonable rate, including the determination of the appropriate liquids pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of the appropriate pipeline index. Accordingly, depending on the FERC’s application of its indexing rate methodology for the next five year term of index rates, the Revised Policy Statement and tax effects related to the Tax Act may impact our revenues associated with any transportation services we may provide pursuant to cost of service based rates in the future, including indexed rates.
Trends and Outlook
Recent market disruptions involving the COVID-19 pandemic have negatively impacted our earnings and cash flows from operations and may continue to do so. Reduced demand for natural gas, NGLs, refined products and/or crude oil caused by the COVID-19 pandemic and a continuation of low WTI crude oil prices may result in the shut-in of production from U.S. oil and gas wells, which in turn may result in decreased volumes transported on our pipeline systems and decreased overall utilization of our midstream services.
With respect to commodity prices, natural gas prices have remained comparatively low in recent months as associated gas from shale oil resources has provided additional supply to the market. Meanwhile, crude oil prices saw a sharp declines as a result of actions by foreign oil-producing nations and a decrease in global demand as result of the COVID-19 pandemic but have subsequently risen and stabilized. We cannot predict the future impacts, or the duration of such impacts, from the COVID-19 pandemic.
The outlook for commodity prices is mixed and could have a varying impact on our business. Reduced demand and increased supply of crude oil has resulted in an increase in worldwide crude oil storage inventories, which is expected to keep crude oil prices suppressed for the foreseeable future. With respect to natural gas markets, a relatively more moderate decrease in demand, coupled with anticipated decreases in gas production associated with wells drilled to produce crude oil, have counterbalanced

softness in pricing. The overall outlook for our midstream services will depend, in part, on the timing and extent of recovery in the commodity markets.
While we anticipate that current and projected commodity prices and the related impact to activity levels in both the upstream and midstream sectors will impact our business, we cannot predict the ultimate magnitude of that impact and expect it to be varied across our operations, depending on the region, customer, type of service, contract term and other factors.
While the vast majority of our counterparties are investment grade rated companies, some of our counterparties may be forced to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court. In this case, we expect that we would attempt to negotiate replacement contracts with those counterparties and, depending on the availability of alternatives to our services, these contracts may have terms that are less favorable to us than the contracts rejected in bankruptcy court.
Ultimately, the extent to which our business will be impacted by recent market developments depends on the factors described above as well as future developments beyond our control, which are highly uncertain and cannot be predicted. In response to these market events and uncertainties, we have cut our already reduced 2020 growth capital spending budget by a total of $600 million and reduced planned operating expenses by approximately $400 million. While current market volatility makes the near-term unpredictable, we believe that overall the long-term demand for our services will continue given the essential nature of the midstream natural gas, NGLs, refined products and crude oil business, although we cannot predict any possible changes in such demand with reasonable certainty.
We currently have ample liquidity to fund our business and we do not anticipate any liquidity concerns in the immediate future (see “Liquidity and Capital Resources” below). In addition, while the trading price of ET common units declined significantly during the first half of 2020, thereby making equity capital market transactions less attractive in the near term, we continue to have access to the debt capital markets on generally favorable terms. In the event we seek additional equity or debt capital, our blended cost of capital for equity and debt is expected to be modestly higher in the near term; however, we will continue to evaluate growth projects and acquisitions as such opportunities may be identified in the future in light of this higher cost of capital.
Results of Operations
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair valueInventory adjustments (excludingthat are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market adjustments)reserves on inventory that is carried at last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Segment Adjusted EBITDA reflectsand consolidated Adjusted EBITDA reflect amounts for less than wholly owned subsidiariesunconsolidated affiliates based on 100%the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.  The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the subsidiaries’ resultsPartnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.
As discussed in Note 1 of operations.the Partnership’s consolidated financial statements included in “Item 1. Financial Statements,” during the first quarter of 2020, the Partnership elected to change its inventory accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. These changes have been applied retrospectively to all prior periods, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

Consolidated Results

 Three Months Ended
September 30,		   Nine Months Ended
September 30,		  
 2017 2016 Change 2017 2016 Change
Segment Adjusted EBITDA:           
Investment in ETP$1,744
 $1,390
 $354
 $4,757
 $4,172
 $585
Investment in Sunoco LP199
 189
 10
 574
 512
 62
Investment in Lake Charles LNG43
 45
 (2) 131
 133
 (2)
Corporate and Other(3) (37) 34
 (25) (142) 117
Adjustments and Eliminations(74) (83) 9
 (211) (208) (3)
Total1,909
 1,504
 405
 5,226
 4,467
 759
Depreciation, depletion and amortization(632) (548) (84) (1,840) (1,596) (244)
Interest expense, net(505) (474) (31) (1,471) (1,336) (135)
Losses on interest rate derivatives(8) (28) 20
 (28) (179) 151
Non-cash unit-based compensation expense(29) (23) (6) (76) (46) (30)
Unrealized gains (losses) on commodity risk management activities(76) (21) (55) 22
 (105) 127
Losses on extinguishments of debt—
 —
 —
 (25) —
 (25)
Inventory valuation adjustments141
 35
 106
 38
 203
 (165)
Equity in earnings of unconsolidated affiliates92
 49
 43
 228
 205
 23
Adjusted EBITDA related to unconsolidated affiliates(205) (157) (48) (554) (503) (51)
Adjusted EBITDA related to discontinued operations(92) (93) 1
 (253) (220) (33)
Impairment of investment in an unconsolidated affiliate—
 (308) 308
 —
 (308) 308
Other, net46
 4
 42
 111
 44
 67
Income (loss) before income tax benefit641
 (60) 701
 1,378
 626
 752
Income tax benefit(157) (89) (68) (97) (151) 54
Income from continuing operations798
 29
 769
 1,475
 777
 698
Income (loss) from discontinued operations, net of income taxes6
 12
 (6) (264) 24
 (288)
Net income$804
 $41
 $763
 $1,211
 $801
 $410
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019* Change 2020 2019* Change
Segment Adjusted EBITDA:           
Intrastate transportation and storage$187
 $290
 $(103) $427
 $542
 $(115)
Interstate transportation and storage403
 460
 (57) 807
 916
 (109)
Midstream367
 412
 (45) 750
 794
 (44)
NGL and refined products transportation and services674
 644
 30
 1,337
 1,256
 81
Crude oil transportation and services519
 752
 (233) 1,110
 1,496
 (386)
Investment in Sunoco LP182
 152
 30
 391
 305
 86
Investment in USAC105
 105
 —
 211
 206
 5
All other1
 10
 (9) 40
 45
 (5)
Adjusted EBITDA (consolidated)2,438
 2,825
 (387) 5,073
 5,560
 (487)
Depreciation, depletion and amortization(936) (785) (151) (1,803) (1,559) (244)
Interest expense, net of interest capitalized(579) (578) (1) (1,181) (1,168) (13)
Impairment losses(4) —
 (4) (1,329) (50) (1,279)
Losses on interest rate derivatives(3) (122) 119
 (332) (196) (136)
Non-cash compensation expense(41) (29) (12) (63) (58) (5)
Unrealized gains (losses) on commodity risk management activities(48) (23) (25) 3
 26
 (23)
Losses on extinguishments of debt—
 —
 —
 (62) (18) (44)
Inventory valuation adjustments (Sunoco LP)90
 4
 86
 (137) 97
 (234)
Adjusted EBITDA related to unconsolidated affiliates(157) (163) 6
 (311) (309) (2)
Equity in earnings of unconsolidated affiliates85
 77
 8
 78
 142
 (64)
Other, net(74) 37
 (111) (101) 20
 (121)
Income (loss) before income tax expense771
 1,243
 (472) (165) 2,487
 (2,652)
Income tax expense(99) (34) (65) (127) (160) 33
Net income (loss)$672
 $1,209
 $(537) $(292) $2,327
 $(2,619)
See the detailed discussion of Segment *As adjusted.
Adjusted EBITDA in “Segment Operating Results” below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for(consolidated). For the three and ninesix months ended SeptemberJune 30, 20172020 compared to the same period last year, increasedAdjusted EBITDA decreased 14% and 9%, respectively, primarily due to additional depreciationthe impacts of lower volumes and market prices among several of our core operating segments; these decreases were partially offset by net increases of approximately $150 million and $290 million, respectively, in Adjusted EBITDA from recent acquisitions and assets placed in service.
Additional discussion of these and other factors affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA in the “Segment Operating Results” section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization fromincreased for the three and six months ended June 30, 2020 compared to the same periods last year due to the acquisition of SemGroup on December 5, 2019, as well as incremental depreciation related to assets recently placed in service.

Interest Expense, Net.Net of Interest Capitalized. Interest expense, net of interest capitalized, increased for the three and ninesix months ended SeptemberJune 30, 2017 increased2020 compared to the same periods last year primarily due to the following:
an increase of $4$67 million of expense recognized by the Partnership primarily attributable to the higher consolidated debt balance following the SemGroup acquisition and related debt refinancing, the impact of which was partially offset by lower borrowing costs on both recently refinanced debt and floating rate debt, and higher capitalized interest.
•
an increase of $3 million for USAC for the six months ended June 30, 2020 compared to the six months ended June 30, 2019 was primarily attributable to a full six months of interest expense incurred in the current period on its senior notes issued in March 2019, which were used to reduce borrowings under the credit agreement, partially offset by reduced borrowings and lower weighted average interest rates under the credit agreement; and
an increase of $3 million for Sunoco LP for the threesix months ended SeptemberJune 30, 20172020 compared to the same period last year primarily related to an increase in Sunoco LP’s total long-term debt.
Impairment Losses. During the prior yearthree months ended March 31, 2020, the Partnership performed an interim impairment test on certain reporting units within midstream, interstate, crude, NGL and all other operations. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $483 million related to our Arklatex and South Texas operations within the midstream segment, a goodwill impairment of $183 million related to our Lake Charles LNG regasification operations with the interstate transportation and storage segment, and a goodwill impairment of $40 million related to our all other operations primarily due to higher interest rates on Sunoco LP’s borrowings under its revolving credit facility that Sunoco LP entered intodecreases in September 2014projected future revenues and an increasecash flows as a result of $51the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million, of expense forduring the ninethree months ended September 30, 2017 compared to the same periodMarch 31, 2020, which is included in the prior year due toPartnership’s consolidated results of operations. During the issuancethree months ended March 31, 2019, USAC recorded a $3 million impairment of Sunoco LP’scompression equipment as a result of its evaluations of the future deployment of USAC’s idle fleet under then-current market conditions. USAC recorded a $4 million impairment of compression equipment during the three months ended June 30, 2020 as a result of its evaluations of the future deployment of its idle fleet under current market conditions.

$800 million 6.250% senior notes on April 7, 2016, as well as the increase in borrowings under Sunoco LP’s revolving credit facility; and
increases of $22 million and $71 million, respectively, of expense recognized by ETP primarily attributable to increases in long-term debt, including the Dakota Access and ETCO term loans that became effective in August 2016.
Losses on Interest Rate Derivatives. Derivatives. Losses on interest rate derivatives during the three and ninesix months ended SeptemberJune 30, 2017 and 20162020 resulted from decreases in forward interest rates.rates, which caused our forward-starting swaps to decrease in value.
Unrealized Gains (Losses) on Commodity Risk Management Activities. Activities. See additional information on the unrealized gains (losses) on commodity risk management activities included in the segment results“Segment Operating Results” below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded duringLosses on Extinguishments of Debt. During the three and ninesix months ended SeptemberJune 30, 2017 and 2016,2020, amounts were related to ETO senior notes redemption in January 2020.
Inventory Valuation Adjustments. Inventory valuation adjustments were recorded for the inventory associated with ETP’s crude oil transportation and service and ETP’s NGL and refined products transportation and services inventories as a result of commodity priceSunoco LP due to changes during the respectivein fuel prices between periods.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment OperationOperating Results” below.
Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that is classified as held for sale.
Other, net. Includes Other, net primarily includes the amortization of regulatory assets and other income and expense amounts.
Income Tax (Expense) Benefit. For the nine months ended September 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $68 million during the periods presented. The remainder of the increase in the effective income tax rate was primarily due to higher nondeductible expenses among the Partnership’s consolidated corporate subsidiaries. In addition, for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. For the three and nine months ended September 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.
Segment Operating Results
Investment in ETP
 Three Months Ended
September 30,		   Nine Months Ended
September 30,		  
 2017 2016 Change 2017 2016 Change
Revenues$6,973
 $5,531
 $1,442
 $20,444
 $15,301
 $5,143
Cost of products sold4,876
 3,844
 1,032
 14,582
 10,280
 4,302
Unrealized (gains) losses on commodity risk management activities81
 15
 66
 (17) 96
 (113)
Operating expenses, excluding non-cash compensation expense(525) (464) (61) (1,543) (1,349) (194)
Selling, general and administrative, excluding non-cash compensation expense(95) (76) (19) (302) (239) (63)
Inventory valuation adjustments(86) (37) (49) (30) (143) 113
Adjusted EBITDA related to unconsolidated affiliates279
 240
 39
 765
 711
 54
Other(7) 25
 (32) 22
 75
 (53)
Segment Adjusted EBITDA$1,744
 $1,390
 $354
 $4,757
 $4,172
 $585
Segment Adjusted EBITDAExpense. For the three months ended SeptemberJune 30, 20172020 compared to the same period in the prior year, income tax expense increased due to higher earnings at our corporate subsidiaries in the current period. For the six months ended June 30, 2020 compared to the same period in the prior year, income tax expense decreased due to the recognition of a taxable gain on the sale of assets at our corporate subsidiaries in the prior period.

Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Equity in earnings (losses) of unconsolidated affiliates:           
Citrus$42
 $39
 $3
 $77
 $71
 $6
FEP18
 14
 4
 (52) 28
 (80)
MEP(2) 7
 (9) (2) 14
 (16)
White Cliffs9
 —
 9
 17
 —
 17
Other18
 17
 1
 38
 29
 9
Total equity in earnings (losses) of unconsolidated affiliates$85
 $77
 $8
 $78
 $142
 $(64)
            
Adjusted EBITDA related to unconsolidated affiliates(1):
           
Citrus$89
 $87
 $2
 $168
 $168
 $—
FEP19
 18
 1
 38
 37
 1
MEP7
 20
 (13) 15
 39
 (24)
White Cliffs13
 —
 13
 27
 —
 27
Other29
 38
 (9) 63
 65
 (2)
Total Adjusted EBITDA related to unconsolidated affiliates$157
 $163
 $(6) $311
 $309
 $2
            
Distributions received from unconsolidated affiliates:           
Citrus$58
 $39
 $19
 $107
 $74
 $33
FEP17
 16
 1
 35
 33
 2
MEP7
 15
 (8) 18
 26
 (8)
White Cliffs10
 —
 10
 23
 —
 23
Other20
 42
 (22) 39
 58
 (19)
Total distributions received from unconsolidated affiliates$112
 $112
 $—
 $222
 $191
 $31
(1)
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:
•
Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
•
Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.

•
Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
•
Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. 
In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.
In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
Intrastate Transportation and Storage
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Natural gas transported (BBtu/d)12,921
 12,115
 806
 13,028
 12,049
 979
Withdrawals from (injections to) storage natural gas inventory (BBtu)(1,910) —
 (1,910) 5,065
 —
 5,065
Revenues$516
 $765
 $(249) $1,109
 $1,621
 $(512)
Cost of products sold248
 400
 (152) 551
 972
 (421)
Segment margin268
 365
 (97) 558
 649
 (91)
Unrealized gains on commodity risk management activities(33) (26) (7) (39) (16) (23)
Operating expenses, excluding non-cash compensation expense(48) (47) (1) (89) (89) —
Selling, general and administrative expenses, excluding non-cash compensation expense(6) (7) 1
 (15) (13) (2)
Adjusted EBITDA related to unconsolidated affiliates6
 5
 1
 12
 11
 1
Segment Adjusted EBITDA$187
 $290
 $(103) $427
 $542
 $(115)
Volumes. For the three and six months ended June 30, 2020 compared to the same periods last year, transported volumes increased primarily due to increased utilization of our Texas pipelines.

Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Transportation fees$148
 $148
 $—
 $309
 $302
 $7
Natural gas sales and other (excluding unrealized gains and losses)68
 173
 (105) 156
 293
 (137)
Retained fuel revenues (excluding unrealized gains and losses)10
 12
 (2) 19
 23
 (4)
Storage margin (excluding unrealized gains and losses)9
 6
 3
 35
 15
 20
Unrealized gains on commodity risk management activities33
 26
 7
 39
 16
 23
Total segment margin$268
 $365
 $(97) $558
 $649
 $(91)
Segment Adjusted EBITDA. For the three months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP increasedour intrastate transportation segment decreased due to the net impactimpacts of the following:

•
a decrease of $105 million in realized natural gas sales and other primarily due to lower realized gains from pipeline optimization activity; and
•
an increase of $1 million in operating expenses primarily due to higher maintenance project costs and higher cost of fuel consumption; partially offset by
an increase of $30$3 million in ETP’s intrastate transportation andrealized storage operations resulting from an increase of $29 million due to higher realized gains from pipeline optimization activity and an increase of $9 million in storage margin. These increases were offset by a decrease in transportation fees due to renegotiated contracts;
an increase of $42 million in ETP’s midstream operations primarily due to a $24 million increase in non-fee based margins due to higher realized crude oil and NGL prices and a $31 million increase in fee-based revenues due to minimum volume commitments in South Texas, increased volumes in the Permian and Northeast regions, and recent acquisitions, including PennTex;
an increase of $40 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $20 million, primarily due to higher volumes on Texas NGL pipelinesstorage optimization and the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $14 million, primarily due to higher NGL volumes from most major producing regions; and an increase in terminal services margin of $7 million due to higher terminal volumes from the Mariner NGL projects; partially offset by an increase in operating expenses due to a legal settlement and a quarterly ad valorem tax true-up;fees.
an increase of $227 million in ETP’s crude oil transportation and services operations due to an increase of $194 million resulting primarily from placing ETP’s Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas; an increase of $28 million from existing assets due to increased volumes throughout the system; and an increase of $18 million due to the impact of LIFO accounting; partially offset by an increase in operating expenses as a result of placing new projects in service and costs associated with increased volumes on the system; and
an increase of approximately $20 million in ETP’s all other operations, primarily due to an increase of $25 million in Adjusted EBITDA related to ETP’s investment in PES of $34 million, offset by decrease of $9 million from ETP’s investment in Sunoco LP. In addition, the three months ended September 30, 2017 experienced an increase of $7 million from commodity trading activities and an increase of $4 million from ETP’s compression operations. These increases were partially offset by higher transaction related expenses, and operating and maintenance expenses from an equipment lease buyout; partially offset by
a decrease of $5 million in ETP’s interstate transportation and storage operations due to an aggregate $12 million decrease in revenue, including decreases on the Panhandle, Trunkline and Transwestern pipelines primarily due to lack of customer demand driven by weak spreads and mild weather, and a decrease of $3 million revenues on the Tiger pipeline due to contract restructuring. The decrease in revenues was partially offset by $10 million of revenues from the Rover pipeline being placed in partial service in August 2017 and by higher income from unconsolidated joint ventures of $9 million primarily due to a legal settlement and lower operating expenses on Citrus.
Segment Adjusted EBITDA. For the ninesix months ended SeptemberJune 30, 20172020 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP increasedour intrastate transportation segment decreased due to the net impactimpacts of the following:
•
a decrease of $137 million in realized natural gas sales and other primarily due to lower realized gains from pipeline optimization activity;
•
a decrease of $4 million in retained fuel revenues primarily due to lower gas prices; and
•
an increase of $2 million in selling, general and administrative expenses primarily due to higher allocated corporate costs; partially offset by
•
an increase of $20 million in realized storage margin primarily due to higher storage optimization;
•
an increase of $7 million in transportation fees primarily due to volume ramp-ups on the Red Bluff Express pipeline and new contracts; and
•
an increase of $1 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to higher fee revenue on the Trans-Pecos and Comanche Trail pipelines.

an increase of $19 million in ETP’s intrastate transportation
Interstate Transportation and storage operations resulting from a $63 million increase dueStorage
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Natural gas transported (BBtu/d)10,152
 10,825
 (673) 10,440
 11,177
 (737)
Natural gas sold (BBtu/d)17
 17
 —
 16
 18
 (2)
Revenues$445
 $493
 $(48) $909
 $991
 $(82)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses(139) (138) (1) (282) (284) 2
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses(16) (18) 2
 (37) (32) (5)
Adjusted EBITDA related to unconsolidated affiliates115
 125
 (10) 221
 244
 (23)
Other(2) (2) —
 (4) (3) (1)
Segment Adjusted EBITDA$403
 $460
 $(57) $807
 $916
 $(109)
Volumes. For the three and six months ended June 30, 2020 compared to higher realized gains from pipeline optimization offset by a $44 million decrease in transportation fees due to renegotiated contracts;
an increase of $213 million in ETP’s midstream operationsthe same periods last year, transported volumes decreased 0.7 Bcf/d primarily due to a $151 million increaseshut-ins of crude production resulting in non-fee based margins due to higher realized crude oillower associated gas and NGL prices and increased volumes in the Permian region and a $93 million increase in fee-based revenues due to minimum volume commitments in South Texas as well as increased volumes in the Permian and Northeast regions, and recent acquisitions, including PennTex. These increases in gross margin were partially offset by increases in operating expenses of $17 million due to recent acquisitions and increases in selling, general and administrative expenses due to a decrease in capitalized overhead, an increase in shared services allocation, an increase in insurance allocation and additional costs from the PennTex acquisition;demand for LNG export.
an increase of $124 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $91 million, primarily due to higher volumes on Texas NGL pipelines and the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $56 million, primarily due to higher NGL volumes from most major producing regions; and an increase of $22 million in marketing margin (excluding changes in unrealized gains of $50 million) primarily due to the timing of the recognition of margin from optimization activities; partially offset by an increase of $39 million in operating expenses primarily due to increased utilities costs associated with our fourth fractionator at Mont Belvieu and the Mariner project ramp up at the Marcus Hook Industrial Complex; and

an increase of $309 million in ETP’s crude oil transportation and services operations due to an increase of $389 million resulting primarily from placing ETP’s Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas; and an increase of $11 million from existing assets due to increased volumes throughout the system; partially offset by an increase in operating expenses as a result of placing new projects in service and costs associated with increased volumes on the system; partially offset by
a decrease of $48 million in ETP’s interstate transportation and storage operations due to an aggregate $63 million decrease in revenue, including decreases on the Panhandle, Trunkline and Transwestern pipelines primarily due to lack of customer demand driven by weak spreads and mild weather, and a decrease of $17 million revenues on the Tiger pipeline due to contract restructuring. The decrease in revenues was partially offset by $10 million of revenues from the Rover pipeline being placed in partial service in August 2017 and by lower operating expenses and selling, general and administrative expenses as well as an increase in income from unconsolidated joint ventures of $7 million primarily due to a legal settlement and lower operating expenses on Citrus offset by lower earnings from Midcontinent Express; and
a decrease of approximately $32 million in ETP’s all other operations, primarily due to a decrease of $66 million related to the termination of ETP’s management fees paid by ETE that ended in 2016 and an increase of $39 million in transaction related expenses partially offset by an increase of $35 million in Adjusted EBITDA related to unconsolidated affiliates, primarily comprising increases of $29 million from ETP’s investment in PES and $3 million from ETP’s investment in Sunoco LP, an increase of $15 million from commodity trading activities and lower expenses related to ETP’s compression operations.
Investment in Sunoco LP
 Three Months Ended
September 30,		   Nine Months Ended
September 30,		  
 2017 2016 Change 2017 2016 Change
Revenues$2,555
 $2,167
 $388
 $7,330
 $5,918
 $1,412
Cost of products sold2,304
 1,975
 329
 6,730
 5,290
 1,440
Operating expenses, excluding non-cash compensation expense(62) (62) —
 (182) (171) (11)
Selling, general and administrative, excluding non-cash compensation expense(21) (42) 21
 (84) (119) 35
Inventory valuation adjustments(56) 1
 (57) (8) (60) 52
Unrealized gains (losses) on commodity risk management activities(5) 6
 (11) (5) 9
 (14)
Adjusted EBITDA from discontinued operations92
 93
 (1) 253
 220
 33
Other—
 1
 (1) —
 5
 (5)
Segment Adjusted EBITDA$199
 $189
 $10
 $574
 $512
 $62
Segment Adjusted EBITDA. For the three months ended SeptemberJune 30, 20172020 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:
•
a decrease of $43 million in reservation fees primarily due to a decrease of $18 million from additional revenue recognized in 2019 associated with a shipper bankruptcy, a decrease of $16 million from lower rates on Lake Charles LNG effective January 2020 and a decrease of $12 million due to less capacity sold on our Panhandle and Trunkline systems as well as lower rates on the sale of uncommitted capacity on our Rover pipeline. These decreases were partially offset by increased margin from our Transwestern system due to increased demand in firm transportation;
•
a decrease of $4 million in interruptible transportation due to lower rates and lower short-term customer demand on our Sea Robin and Transwestern systems; and
•
a decrease of $10 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower earnings of $12 million from our Midcontinent Express Pipeline joint venture as a result of less capacity sold and lower rates received following the expiration of certain contracts, partially offset by a $2 million increase from Citrus primarily due to higher margins and lower operating expenses.
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:
•
a decrease of $73 million in reservation fees primarily due to a decrease of $18 million from additional revenue recognized in 2019 associated with a shipper bankruptcy, a decrease of $30 million due to less capacity sold at lower rates on our Panhandle and Trunkline system as well as lower rates on the sale of uncommitted capacity on our Rover pipeline, and a decrease of $32 million due to a contractual rate adjustment on commitments at our Lake Charles LNG facility. These decreases were partially offset by increased revenues from our Transwestern system due to increased demand in firm transportation;
a decrease of $8 million in operational gas sales, interruptible transportation, parking and storage revenue due to unfavorable market conditions;
an increase of $5 million in selling, general and administrative expenses primarily due to higher allocated overhead costs and an increase in reserves for insurance claims; and
a decrease of $23 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower earnings from our Midcontinent Express Pipeline joint venture as a result of less capacity sold and lower rates received following the expiration of certain contracts; partially offset by

a decrease of $2 million in operating expenses primarily due to lower employee costs resulting from cost-cutting initiatives of $10 million and an $8 million decrease in ad valorem taxes, partially offset by bad debt expense of $10 million and a $5 million change in lower of cost or market adjustments.
Midstream
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Gathered volumes (BBtu/d)12,964
 13,148
 (184) 13,155
 12,934
 221
NGLs produced (MBbls/d)602
 565
 37
 606
 564
 42
Equity NGLs (MBbls/d)37
 30
 7
 37
 33
 4
Revenues$1,018
 $1,198
 $(180) $2,188
 $2,916
 $(728)
Cost of products sold473
 584
 (111) 1,048
 1,725
 (677)
Segment margin545
 614
 (69) 1,140
 1,191
 (51)
Operating expenses, excluding non-cash compensation expense(166) (189) 23
 (359) (372) 13
Selling, general and administrative expenses, excluding non-cash compensation expense(20) (23) 3
 (46) (42) (4)
Adjusted EBITDA related to unconsolidated affiliates7
 9
 (2) 14
 15
 (1)
Other1
 1
 —
 1
 2
 (1)
Segment Adjusted EBITDA$367
 $412
 $(45) $750
 $794
 $(44)
Volumes. Gathered volumes decreased during the three months ended June 30, 2020 compared to the same period last year primarily due to decreases in the South Texas and North Texas regions, partially offset by the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region. NGL production increased due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and increased ethane recovery in the Permian, South Texas and North Texas regions.
Gathered volumes increased during the six months ended June 30, 2020 compared to the same period last year primarily due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and volume increases in the Northeast region, partially offset by decreases in the South Texas region. NGL production increased due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and increased ethane recovery in the Permian, South Texas and North Texas regions.
Segment Margin. The table below presents the components of our midstream segment margin. For the prior period included in the table below, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect reclassification of certain contractual minimum fees in order to conform to the current period classification:
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Gathering and processing fee-based revenues$503
 $530
 $(27) $1,033
 $1,034
 $(1)
Non-fee-based contracts and processing42
 84
 (42) 107
 157
 (50)
Total segment margin$545
 $614
 $(69) $1,140
 $1,191
 $(51)
Segment Adjusted EBITDA. For the three months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
a decrease $39 million in non-fee-based margin due to lower NGL prices;
a decrease of $3 million in non-fee-based margin due to decreased throughput volume in the South Texas region; and
•
a decrease of $27 million in fee-based margin due to volume declines in the South Texas and North Texas regions; partially offset by

a decrease of $23 million in operating expenses due to decreases of $11 million in outside services, $8 million in employee costs and $3 million in materials; and
•
a decrease of $3 million in selling, general and administrative expenses due to a decrease in allocated overhead costs.
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
•
a decrease of $61 million in non-fee-based margin due to lower NGL prices of $56 million and lower gas prices of $5 million;
an increase of $4 million in selling, general and administrative expenses due to an increase of $3 million in capitalized overhead costs and an increase of $1 million in insurance; partially offset by
•
an increase of $11 million in non-fee-based margin due to increased throughput volume in the Mid-Continent/Panhandle region as a result of the SemGroup acquisition; and
•
a decrease of $13 million in operating expenses due to decreases of $11 million in outside services, $4 million in employee costs and $3 million in materials, partially offset by an increase of $7 million in maintenance project costs.
NGL and Refined Products Transportation and Services
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
NGL transportation volumes (MBbls/d)1,401
 1,305
 96
 1,400
 1,237
 163
Refined products transportation volumes (MBbls/d)377
 628
 (251) 460
 623
 (163)
NGL and refined products terminal volumes (MBbls/d)748
 885
 (137) 798
 831
 (33)
NGL fractionation volumes (MBbls/d)836
 701
 135
 820
 690
 130
Revenues$2,119
 $2,612
 $(493) $4,834
 $5,643
 $(809)
Cost of products sold1,368
 1,848
 (480) 3,204
 4,174
 (970)
Segment margin751
 764
 (13) 1,630
 1,469
 161
Unrealized losses on commodity risk management activities78
 39
 39
 23
 96
 (73)
Operating expenses, excluding non-cash compensation expense(154) (155) 1
 (313) (304) (9)
Selling, general and administrative expenses, excluding non-cash compensation expense(19) (26) 7
 (44) (45) 1
Adjusted EBITDA related to unconsolidated affiliates18
 21
 (3) 41
 39
 2
Other—
 1
 (1) —
 1
 (1)
Segment Adjusted EBITDA$674
 $644
 $30
 $1,337
 $1,256
 $81
Volumes. For the three and six months ended June 30, 2020 compared to the same periods last year, NGL transportation volumes increased due to higher throughput volumes on our Mariner East pipeline system. In addition, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions.
Refined products transportation volumes decreased for the three and six months ended June 30, 2020 compared to the same periods last year due to the closure of a third-party refinery during the third quarter of 2019, which negatively impacted supply to our refined products transportation system, and less domestic demand for jet fuel and other refined products. These decreases in volumes are partially offset by the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019.
NGL and refined products terminal volumes decreased for the three and six months ended June 30, 2020 compared to the same periods last year primarily due to the closure of a third-party refinery during the third quarter of 2019, and less domestic demand for jet fuel and other refined products. These decreases were partially offset by higher volumes from our Mariner East system,

and the initiation of service on our JC Nolan diesel fuel pipeline and natural gasoline export project, both of which commenced service in the third quarter of 2019.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased 20% for the three and six months ended June 30, 2020 compared to the same periods last year primarily due to the commissioning of our sixth and seventh fractionators in February 2019 and February 2020, respectively.
Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Transportation margin$449
 $422
 $27
 $925
 $785
 $140
Fractionators and refinery services margin173
 154
 19
 352
 320
 32
Terminal services margin129
 166
 (37) 280
 303
 (23)
Storage margin55
 53
 2
 118
 109
 9
Marketing margin23
 8
 15
 (22) 48
 (70)
Unrealized losses on commodity risk management activities(78) (39) (39) (23) (96) 73
Total segment margin$751
 $764
 $(13) $1,630
 $1,469
 $161
Segment Adjusted EBITDA. For the three months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
•
an increase of $27 million in transportation margin primarily due to a $28 million increase from higher throughput volumes on our Mariner East pipeline system, an $11 million increase from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $6 million increase due to the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019, and a $4 million increase due to higher throughput volumes from the Southeast Texas region. These increases were partially offset by an $8 million decrease due to a reclassification between our transportation and fractionators margins, a $7 million decrease due to less domestic demand for jet fuel and other refined products, a $5 million decrease resulting from the closure of a third-party refinery during the third quarter of 2019, and a $2 million decrease due to lower third-party volumes on our Mariner West pipeline;
•
an increase of $15 million in marketing margin primarily due to a $50 million increase due to higher optimization gains from the sale of NGL component products at our Mont Belvieu facility and a $10 million increase due to write-downs of NGL inventory in the second quarter of 2019. These increases were partially offset by lower gains from our butane blending business during the second quarter of 2020 due to unfavorable market conditions; and
•
an increase of $19 million in fractionators and refinery services margin primarily due to a $15 million increase resulting from the commissioning of our seventh fractionator in February 2020 and higher NGL volumes from the Permian and Barnett regions feeding our Mont Belvieu fractionation facility, and an increase of $8 million due to a reclassification between our transportation and fractionators margins. These increases were partially offset by a $4 million decrease due to the expiration of a third-party blending contract during the second quarter of 2020; partially offset by
•
a decrease of $37 million in terminal services margin primarily due to a $25 million decrease resulting from the expiration of a third party contract at our Nederland export facility in the second quarter of 2020, a $9 million decrease due to lower third-party and intercompany volumes feeding our Marcus Hook Industrial Complex, a $6 million decrease due to less domestic demand for jet fuel and other refined products, and a $4 million decrease due to the closure of a third-party refinery. These decreases were partially offset by a $6 million increase due to higher throughput on our Mariner East system.

Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
•
an increase of $140 million in transportation margin primarily due to a $103 million increase from higher throughput volumes on our Mariner East pipeline system, a $46 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $14 million increase due to the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019, a $9 million increase due to higher throughput volumes from the Barnett region, and a $6 million increase due to higher throughput from the Southeast Texas region. These increases were partially offset by an $11 million decrease resulting from the closure of a third-party refinery during the third quarter of 2019, a $10 million decrease due to less domestic demand for jet fuel and other refined products, an $8 million decrease due to a reclassification between our transportation and fractionators margins, a $5 million decrease due to lower volumes from the Eagle Ford region, and a $3 million decrease due to lower third-party volumes on our Mariner West pipeline;
•
an increase of $32 million in fractionators and refinery services margin primarily due to a $25 million increase resulting from the commissioning of our sixth and seventh fractionators in February 2019 and February 2020, respectively, and higher NGL volumes from the Permian and Barnett regions feeding our Mont Belvieu fractionation facility, an $8 million increase due to a reclassification between our transportation and fractionators margins, and a $3 million increase in truck and rail volumes feeding our refinery services facility. These increases were partially offset by a $6 million decrease due to the expiration of a third-party blending contract during the second quarter of 2020; and
•
an increase of $9 million in storage margin primarily due to a $6 million increase in fees generated from exported volumes and a $3 million increase from higher throughput; partially offset by
•
a decrease of $70 million in marketing margin primarily due to a $54 million decrease due to lower gains from our butane and gasoline blending business due to unfavorable market conditions, a $35 million decrease from capacity lease fees incurred by our marketing affiliate on our Mariner East pipeline system and a $12 million decrease due to fewer export and rack sales. These decreases were partially offset by higher optimization gains from the sale of NGL component products at our Mont Belvieu facility;
•
a decrease of $23 million in terminal services margin primarily due to a $25 million decrease resulting from the expiration of a third-party contract at our Nederland export facility in the second quarter of 2020, a $16 million decrease due to lower third-party and intercompany volumes feeding our Marcus Hook Industrial Complex, a $10 million decrease due to a closure of a third-party refinery, and an $8 million decrease due to less domestic demand for jet fuel and other refined products. These decreases were partially offset by a $33 million increase due to higher throughput on our Mariner East system and a $3 million increase resulting from initiation of service of our natural gasoline export in the third quarter of 2019; and
•
an increase of $9 million in operating expenses primarily due to increases totaling $15 million for costs associated with operating additional assets as well as an increase in throughput volumes, partially offset by a $5 million reduction to lower power costs.

Crude Oil Transportation and Services
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Crude transportation volumes (MBbls/d)3,590
 4,266
 (676) 4,021
 4,158
 (137)
Crude terminals volumes (MBbls/d)2,716
 2,846
 (130) 2,851
 2,704
 147
Revenues$1,839
 $5,046
 $(3,207) $6,052
 $9,232
 $(3,180)
Cost of products sold1,175
 4,136
 (2,961) 4,633
 7,298
 (2,665)
Segment margin664
 910
 (246) 1,419
 1,934
 (515)
Unrealized (gains) losses on commodity risk management activities—
 11
 (11) 10
 (98) 108
Operating expenses, excluding non-cash compensation expense(131) (150) 19
 (289) (300) 11
Selling, general and administrative expenses, excluding non-cash compensation expense(26) (20) (6) (54) (40) (14)
Adjusted EBITDA related to unconsolidated affiliates11
 1
 10
 23
 (1) 24
Other1
 —
 1
 1
 1
 —
Segment Adjusted EBITDA$519
 $752
 $(233) $1,110
 $1,496
 $(386)
Volumes. For the three months ended June 30, 2020 compared to the same period last year, crude transportation and terminal volumes were lower due to decreased demand on our Texas pipeline system and our Bakken pipeline, driven by lower production in these regions as well as lower refinery utilization, partly offset by contributions from assets acquired in 2019.
For the six months ended June 30, 2020 compared to the same period last year, crude transportation volumes were lower due to decreased demand on our Texas pipeline system and our Bakken pipeline, driven by lower production in these regions and lower refinery utilization. Terminal volumes were higher due to contributions from assets acquired in 2019.
Segment Adjusted EBITDA. For the three months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impacts of the following:
•
a decrease of $257 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $62 million decrease (excluding a net change of $11 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business due to well shut-ins resulting in unfulfilled producer supply commitments, as well as unfavorable pricing conditions impacting our Permian to Gulf Coast and Bakken to Gulf Coast trading operations, a $123 million decrease from our Texas crude pipeline system due to lower utilization due in part to well shut-ins, as well as lower average tariff rates realized, a $117 million decrease due to lower volumes on our Bakken Pipeline resulting from well shut-ins, a $10 million decrease in marine throughput at our crude terminals, and a $7 million decrease due to lower volumes on our Bayou Bridge Pipeline, partially offset by an increase of $74 million related to assets acquired in 2019; and
•
an increase of $6 million in selling, general and administrative expenses primarily due to a $3 million increase in legal expenses, and a $2 million increase in insurance expenses, partially offset by a $1 million decrease in allocated overhead costs; offset by
•
a decrease of $19 million in operating expenses primarily due to lower volume-driven pipeline expenses, partially offset by increased costs related to assets acquired in 2019; and
•
an increase of $10 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired in 2019.
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impacts of the following:
a decrease of $407 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $268 million decrease (excluding a net change of $108 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business due primarily to unfavorable pricing conditions, as well as unfulfilled producer supply commitments due to well shut-ins, impacting our Permian to Gulf Coast

and Bakken to Gulf Coast trading operations, a $194 million decrease from our Texas crude pipeline system due to lower utilization due in part to well shut-ins, as well as lower average tariff rates realized, a $97 million decrease due to lower volumes on our Bakken Pipeline resulting from well shut-ins, and an $8 million decrease in marine throughput at our crude terminals, offset by a $162 million increase related to assets acquired in 2019 and an $11 million increase due to higher volumes on our Bayou Bridge Pipeline; and
•
an increase of $14 million in selling, general and administrative expenses primarily due to a $4 million increase in legal expenses, a $4 million increase related to assets acquired in 2019, a $2 million increase in insurance expenses, and a $2 million increase in allocated overhead costs; partially offset by
•
a decrease of $11 million in operating expenses primarily due to lower volume-driven pipeline expenses, partially offset by increased costs related to assets acquired in 2019; and
•
an increase of $24 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired in 2019.
Investment in Sunoco LP
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Revenues$2,080
 $4,475
 $(2,395) $5,352
 $8,167
 $(2,815)
Cost of products sold1,722
 4,206
 (2,484) 4,886
 7,528
 (2,642)
Segment margin358
 269
 89
 466
 639
 (173)
Unrealized (gains) losses on commodity risk management activities—
 3
 (3) 6
 (3) 9
Operating expenses, excluding non-cash compensation expense(72) (89) 17
 (181) (187) 6
Selling, general and administrative expenses, excluding non-cash compensation expense(22) (31) 9
 (52) (55) 3
Adjusted EBITDA related to unconsolidated affiliates3
 —
 3
 5
 —
 5
Inventory valuation adjustments(90) (4) (86) 137
 (97) 234
Other5
 4
 1
 10
 8
 2
Segment Adjusted EBITDA$182
 $152
 $30
 $391
 $305
 $86
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impacts of the following:
an increase in wholesale motor fuel revenue due to a higher sales price per wholesale motor fuel gallon, and an increase in wholesale motor fuel gallons sold offset by higher cost of products sold, excluding a $56 million favorable inventory adjustment change from 2016;
a net increase in other revenue consisting of merchandise, rental income and retail motor fuel of $8 million; and
•
an increase of $16 million in motor fuel sales as a result of an increase in gross profit per gallon sold, partially offset by a decrease in gallons sold;
a decrease of $26 million in operating expenses and selling, general and administrative expenses, of $21 millionexcluding non-cash compensation expense, primarily dueattributable to higherlower employee costs, in 2016 related to relocation, employee termination,maintenance, advertising, credit card fees and higher contract laborutilities; and professional fees as Sunoco LP transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas, to Dallas during 2016.
•
an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates which was attributable to the JC Nolan joint venture entered into in 2019; partially offset by
•
a decrease of $15 million in non-motor fuel sales gross margin as a result of reduced credit card transactions related to the COVID-19 pandemic.
Segment Adjusted EBITDA.For the ninesix months ended SeptemberJune 30, 20172020 compared to the same period last year, Segment Adjusted EBITDA related to the Investmentour investment in Sunoco LP segment increased due to the net impactimpacts of the following:
•
an increase of $84 million in motor fuel sales as a result of a 39.6% increase in gross profit per gallon sold and the receipt of a $13 million make-up payment under the fuel supply agreement with 7-Eleven, Inc.; partially offset by a 14.6% decrease in gallons sold;

•
a decrease of $9 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation expense, primarily attributable to lower employee costs, maintenance, advertising, credit card fees and utilities. This decrease is primarily offset by a $16 million charge for current credit losses on Sunoco LP’s accounts receivable in connection with the financial impact from COVID-19; and
•
an increase in unconsolidated affiliate Adjusted EBITDA of $5 million, which was attributable to the JC Nolan joint venture entered into in 2019; partially offset by
•
a decrease of $13 million in non motor fuel sales primarily due to reduced credit card transactions related to the COVID-19 pandemic.
Investment in wholesale motor fuel revenue dueUSAC
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Revenues$169
 $174
 $(5) $348
 $345
 $3
Cost of products sold18
 24
 (6) 42
 46
 (4)
Segment margin151
 150
 1
 306
 299
 7
Operating expenses, excluding non-cash compensation expense(30) (32) 2
 (65) (67) 2
Selling, general and administrative expenses, excluding non-cash compensation expense(16) (13) (3) (30) (26) (4)
Segment Adjusted EBITDA$105
 $105
 $—
 $211
 $206
 $5
The Investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended June 30, 2020 Segment Adjusted EBITDA related to a higher sales price per wholesale motor fuel gallon, and an increaseour investment in wholesale motor fuel gallons sold offset by higher cost of products soldUSAC segment was consistent with the same period last year primarily due to an unfavorable inventory adjustment changes;the offsetting impacts of the following:
•
an increase of $3 million in selling, general and administrative expenses primarily due to an increase in the provision for expected credit losses; offset by
•
a decrease of $2 million in operating expenses, as well as an increase of $1 million in segment margin primarily due to a decrease in cost of products sold offset by a decrease in revenues as a result of a decrease in average revenue generating horsepower.
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment decreased due to the net impacts of the following:
•
an increase of $7 million in segment margin primarily due to an increase revenues as a result of an increase in fleet horsepower and a decrease in cost of products sold; partially offset by
•
an increase of $4 million in selling, general and administrative expenses primarily due to an increase in the provision for expected credit losses.


All Other
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Revenues$492
 $391
 $101
 $1,005
 $888
 $117
Cost of products sold377
 343
 34
 792
 798
 (6)
Segment margin115
 48
 67
 213
 90
 123
Unrealized (gains) losses on commodity risk management activities2
 (4) 6
 (3) (5) 2
Operating expenses, excluding non-cash compensation expense(27) (6) (21) (65) (13) (52)
Selling, general and administrative expenses, excluding non-cash compensation expense(22) (23) 1
 (57) (34) (23)
Adjusted EBITDA related to unconsolidated affiliates—
 2
 (2) —
 1
 (1)
Other and eliminations(67) (7) (60) (48) 6
 (54)
Segment Adjusted EBITDA$1
 $10
 $(9) $40
 $45
 $(5)
Amounts reflected in our all other segment primarily include:
our natural gas marketing operations;
our wholly-owned natural gas compression operations;
our investment in coal handling facilities; and
our Canadian operations, which were acquired in the SemGroup acquisition in December 2019 and include natural gas gathering and processing assets.
Segment Adjusted EBITDA. For the three months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:
•
a decrease of $7 million due to lower sales of residue gas;
•
a decrease of $11 million due to lower revenues from our compression equipment business;
a decrease of $7 million due to power trading activities;
a decrease in selling, generalof $5 million due to lower demand and administrative expensesoperator production at our natural resources business;
•
a decrease of $4 million due to storage gains; and
•
a decrease of $3 million from increased power costs at our compression services business; partially offset by
•
an increase of $25 million from the acquisition of SemCAMS; and
•
an increase of $6 million in settled derivatives.
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of $35the following:
a decrease of $9 million primarilyfrom power trading activities;
a decrease of $9 million due to lower sales of residue gas;
a decrease of $6 million due to lower gas prices and increased power costs at our compression services business;
a decrease of $4 million due to storage, park and loan operations;
a decrease of $18 million due to lower revenue from our compression equipment business;
a decrease of $24 million due to higher costs in 2016 related to relocation, employee termination,merger and higher contract labor and professional fees as Sunoco LP transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas, to Dallas during 2016; andacquisition expense;
an increase in adjusted EBITDA from discontinued operationsa decrease of $33$8 million primarily due to an increaselower demand and operator production at our natural resources business; and

a decrease of $73$5 million due to the elimination of Sunoco LP’s interest in the gross profit offset by an increase of $48 million in selling, general and administrative expenses related to discontinued operations;our JC Nolan joint venture; partially offset by
an increase in other operating expenses of $11$51 million primarily attributable tofrom the acquisition of the fuels businessSemCAMS;
an increase of $17 million from Emerge Energy Services LPsettlement payments received from our ownership of PES; and
an increase of $8 million in August of 2016 as well as increases of utilities, maintenance expenses, property taxes and credit card processing fees in our retail business.
Investment in Lake Charles LNG
 Three Months Ended
September 30,		   Nine Months Ended
September 30,		  
 2017 2016 Change 2017 2016 Change
Revenues$49
 $50
 $(1) $148
 $148
 $—
Operating expenses, excluding non-cash compensation expense(6) (4) (2) (15) (13) (2)
Selling, general and administrative, excluding non-cash compensation expense—
 (1) 1
 (2) (2) —
Segment Adjusted EBITDA$43
 $45
 $(2) $131
 $133
 $(2)
Lake Charles LNG derives all of its revenue from a long-term contract with BG Group plc.settled derivatives.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Parent Company Only
The Parent Company’s principal sources of cash flow are derived from distributions related to its direct and indirectinvestment in ETO, which derives its cash flows from its subsidiaries, including ETO’s investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The amount of cash that our subsidiaries distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below. In connection with previous transactions, we have relinquished a portion of incentive distributions to be received, and we may agree to do so in the future, in connection with transactions or otherwise.USAC.
The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with cash flows from its distributions from ETP, Sunoco LPdirect and Lake Charles LNG.indirect investments in ETO. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its unitholdersUnitholders on a quarterly basis.
We expect ourThe Parent Company expects ETO and its respective subsidiaries and investments in Sunoco LP and USAC to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deemit deems prudent to provide liquidity for new capital projects of ourits subsidiaries or for other partnership purposes.
ETP
ETP’sOur ability to satisfy its obligations and pay distributions to its unitholders will depend on itsour future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.
We currently expect capital expenditures in 2020 to be within the control of ETP’s management.following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC):
 Growth Maintenance
 Low High Low High
Intrastate transportation and storage$10
 $20
 $40
 $45
Interstate transportation and storage (1)
75
 100
 115
 120
Midstream450
 475
 105
 110
NGL and refined products transportation and services2,425
 2,525
 95
 105
Crude oil transportation and services (1)
275
 300
 130
 140
All other (including eliminations)75
 100
 55
 60
Total capital expenditures$3,310
 $3,520
 $540
 $580
(1)
Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.
The assets used in ETP’sour natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, ETP doeswe do not have any

significant financial commitments for maintenance capital expenditures in itsour businesses. From time to time ETP experienceswe experience increases in pipe costs due to a number of reasons,factors, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe in a timely, manner, higher steel prices and other factors beyond ETP’s control. However, ETPour control; however, we have included these factors in itsour anticipated growth capital expenditures for each year.
ETPWe generally funds itsfund maintenance capital expenditures and distributions with cash flows from operating activities. ETPWe generally fundsfund growth capital expenditures with proceeds of borrowings under the ETP Credit Facility,credit facilities, long-term debt, the issuance of additional ETP commonpreferred units dropdown proceeds or the monetization of non-core assets or a combination thereof.
Sunoco LP
Sunoco LP’s ability to satisfy its obligations and pay distributions to its unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond the control of Sunoco LP’s management.
Sunoco LP currently expects to spend approximately $150$30 million on growth capital and $70$75 million on maintenance capital for the full year 2017.2020.

USAC
USAC currently plans to spend approximately $30 million on maintenance capital expenditures during 2020, including parts consumed from inventory.
Without giving effect to any equipment USAC may acquire pursuant to any future acquisitions, it currently has budgeted between $80 million and $90 million in expansion capital expenditures during 2020. As of June 30, 2020, USAC has binding commitments to purchase $18 million of additional compression units and serialized parts, all of which USAC expects to be delivered throughout 2020.
Cash Flows
Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price forof our operating entitiessubsidiaries’ products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities.liabilities (net of effects of acquisitions). Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash unit-based compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from the construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we haveETO has a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchases and sales of inventories and the timing of advances and deposits received from customers.
NineSix months ended SeptemberJune 30, 20172020 compared to ninesix months ended SeptemberJune 30, 20162019. Cash provided by operating activities during 20172020 was $3.30$3.14 billion as compared to $2.22$3.89 billion for 2016. Net2019, and net loss was $292 million for 2020 and net income was $1.21$2.33 billion and $801 million for 2017 and 2016, respectively.2019. The difference between net incomeloss and the net cash provided by operating activities for the ninesix months ended SeptemberJune 30, 2017 and 2016,2020 primarily consisted of non-cash items totaling $1.40 billion and $898 million, respectively, and net changes in operating assets and liabilities (net of $222effects of acquisitions) of $65 million and $48 million, respectively. The nine months ended September 30, 2016, included a $308 million impairment of investment in an unconsolidated affiliate.other non-cash items totaling $3.37 billion.
The non-cash activity in 20172020 and 20162019 consisted primarily of depreciation, depletion and amortization of $1.84$1.80 billion and $1.60$1.56 billion, respectively, equity in earningsnon-cash compensation expense of unconsolidated affiliates of $228$63 million and $205$58 million, respectively, inventory valuation adjustments of $38$137 million and $203$97 million, respectively, and deferred income taxes of $120$125 million and $139$138 million, respectively. Non-cash activity also included losses on extinguishments of debt in 2020 and 2019 of $62 million and $18 million, respectively, impairment losses of $1.33 billion and unit-based compensation expense$50 million in 2020 and 2019, respectively.
Unconsolidated affiliate activity consisted of $76equity in earnings of $78 million and $46$142 million in 2020 and 2019, respectively, and cash distributions received of $125 million and $170 million, respectively.
Cash paid for interest, net of interest capitalized, was $1.41$1.06 billion and $1.43$1.09 billion for the ninesix months ended SeptemberJune 30, 20172020 and 2016,2019, respectively.
Capitalized interest Interest capitalized was $177$106 million and $148$94 million for the ninesix months ended SeptemberJune 30, 20172020 and 2016,2019, respectively.

Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid infor acquisitions, capital expenditures, cash distributions fromcontributions to our joint ventures, and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership’s investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.
NineSix months ended SeptemberJune 30, 20172020 compared to ninesix months ended SeptemberJune 30, 2016. 2019. Cash used in investing activities during 20172020 was $4.76$2.76 billion as compared to cash used in investing activities $6.08$2.94 billion for 2016.2019. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 20172020 were $6.10 billion. This compares$2.85 billion compared to total$2.78 billion

for 2019. Additional detail related to our capital expenditures (excludingis provided in the allowancetable below. During 2019, we received $93 million of cash proceeds from the sale of a noncontrolling interest in a subsidiary and paid $7 million in cash for equity funds used during constructionall other acquisitions.
The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover and Bayou Bridge pipeline projects and net of contributions in aid of construction costs) on an accrual basis for 2016 of $5.88 billion. During the ninesix months ended SeptemberJune 30, 2017, we had proceeds from transactions of $1.4 billion.2020:
 Capital Expenditures Recorded During Period
 Growth Maintenance Total
Intrastate transportation and storage$2
 $34
 $36
Interstate transportation and storage22
 34
 56
Midstream243
 55
 298
NGL and refined products transportation and services1,340
 39
 1,379
Crude oil transportation and services115
 37
 152
Investment in Sunoco LP50
 9
 59
Investment in USAC69
 13
 82
All other (including eliminations)56
 18
 74
Total capital expenditures$1,897
 $239
 $2,136
Financing Activities
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distribution increasesDistributions increase between the periods were based on increases in distribution rates, increases in the number of common units outstanding at our subsidiaries andor increases in the number of our common units outstanding.distribution rate.
NineSix months ended SeptemberJune 30, 20172020 compared to ninesix months ended SeptemberJune 30, 2016.2019. Cash used in financing activities during 20172020 was $1.30 billion as$508 million compared to cash provided by financing activities of $3.92$926 million for 2019. During 2020 and 2019, our subsidiaries received $1.58 billion for 2016. In 2017, ETE received $2.20 billionand $780 million, respectively, in net proceeds from offerings of ETE common units and subsidiary common units as compared to $2.10 billion in 2016. In 2016, Sunoco Logistics received $1.31 billion in net proceeds from offerings of their commonpreferred units. During 2017,2020, we had a consolidated net increase in our debt level of $1.40 billion as$206 million compared to a net increase of $4.33 billion$538 million for 2016.2019. In 2017,2020 and 2019, we paid net proceeds on affiliates notes in the amountdebt issuance costs of $255 million. We have$50 million and $87 million, respectively.
In 2020 and 2019, we paid distributions of $752$1.58 billion and $1.55 billion, respectively, to our partners. In 2020 and 2019, we paid distributions of $852 million and $780$813 million, to our partners in 2017 and in 2016, respectively. Our subsidiaries have paid distributionsrespectively, to noncontrolling interestinterests. In addition, we received capital contributions of $2.16 billion and $2.03 billion$178 million in 2017 and 2016, respectively.cash from noncontrolling interests in 2020 compared to $206 million in cash from noncontrolling interests in 2019.

Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
 September 30, 2017 December 31, 2016
Parent Company Indebtedness:   
ETE Senior Notes due October 2020$1,187
 $1,187
ETE Senior Notes due January 20241,150
 1,150
ETE Senior Notes due June 20271,000
 1,000
ETE Senior Secured Term Loan, due December 2, 20192,200
 2,190
ETE Senior Secured Revolving Credit Facility1,191
 875
Subsidiary Indebtedness:   
ETP Senior Notes20,540
 19,440
Panhandle Senior Notes1,085
 1,085
Sunoco, Inc. Senior Notes65
 465
Sunoco Logistics Senior Notes7,600
 5,350
Transwestern Senior Notes575
 657
Sunoco LP Senior Notes, Term Loan and lease-related obligation3,581
 3,561
Credit Facilities and Commercial Paper:   
ETLP $3.75 billion Revolving Credit Facility due November 2019 (1)
2,056
 2,777
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 (2)
35
 1,292
Sunoco Logistics $1.00 billion 364-Day Credit Facility due December 2017 (3)
—
 630
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019644
 1,000
Bakken Term Note2,500
 1,100
PennTex $275 million Revolving Credit Facility due December 2019—
 168
Other Long-Term Debt5
 31
Unamortized premiums and fair value adjustments, net65
 101
Deferred debt issuance costs(268) (257)
Total45,211
 43,802
Less: Current maturities of long-term debt716
 1,194
Long-term debt and notes payable, less current maturities$44,495
 $42,608
 June 30,
2020		 December 31,
2019
Parent Company Indebtedness:   
ET Senior Notes due October 2020$—
 $52
ET Senior Notes due March 20235
 5
ET Senior Notes due January 202423
 23
ET Senior Notes due June 202744
 44
Subsidiary Indebtedness:   
ETO Senior Notes37,783
 36,118
Transwestern Senior Notes400
 575
Panhandle Senior Notes235
 235
Bakken Senior Notes2,500
 2,500
Sunoco LP Senior Notes and lease-related obligations2,929
 2,935
USAC Senior Notes1,475
 1,475
Credit facilities and commercial paper:   
ETO $2.00 billion Term Loan facility due October 20222,000
 2,000
ETO $5.00 billion Revolving Credit Facility due December 2023 (1)
3,010
 4,214
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023158
 162
USAC $1.60 billion Revolving Credit Facility due April 2023448
 403
HFOTCO Tax Exempt Notes due 2050225
 225
SemCAMS Revolver due February 202492
 92
SemCAMS Revolver Term Loan A due February 2024251
 269
Other long-term debt11
 2
Net unamortized premiums, discounts, and fair value adjustments(11) 4
Deferred debt issuance costs(293) (279)
Total debt51,285
 51,054
Less: current maturities of long-term debt34
 26
Long-term debt, less current maturities$51,251
 $51,028
(1) 
Includes $2.06$1.11 billion and $777 million$1.64 billion of commercial paper outstanding at SeptemberJune 30, 20172020 and December 31, 2016,2019, respectively.
(2)
Includes $50 million of commercial paper outstanding at December 31, 2016.
(3)
Sunoco Logistics’ $1.00 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics had the ability and intent to refinance such borrowings on a long-term basis. This 364-Day Credit Facility was terminated and repaid in May 2017.
Senior Notes and Term LoanRecent Transactions
Energy Transfer Equity, L.P.ETO January 2020 Senior Notes Offering and Redemption
In October 2017, ETE issued $1On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.
ETE Term Loan Facility
On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof.

Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in ETP or (b) equity interests of any person which owns, directly or indirectly, IDRs in ETP, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.
Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.
On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.
In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.
Sunoco LP Term Loan Waiver
Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of September 30, 2017, the balance on the term loan was $1.24 billion.
ETP2.900% Senior Notes Redemption
In October 2017, ETP redeemed all of the outstanding $500 million aggregate principal amount of ETLP’s 6.50% senior notes due July 2021 and all of the outstanding $700 million aggregate principal amount of ETLP’s 5.50% senior notes due April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.
ETP Senior Notes Offering 
In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and2025, $1.50 billion aggregate principal amount of 5.40%the Partnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of the Partnership’s 5.000% Senior Notes due 2050 (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Partners Operations L.P., on a senior notes due 2047. The $2.22 billion netunsecured basis.
Utilizing proceeds from the offering were used to redeem all of the $500January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of ETLP’s 6.5% senior notes5.75% Senior Notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility (described below)September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET's $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and for general partnership purposes.Transwestern's $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.

Credit Facilities and Commercial Paper
Parent CompanyETO Term Loan
ETO’s term loan credit agreement provides for a $2 billion three-year term loan credit facility (the “ETO Term Loan”). Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The ETO Term Loan is unsecured and is guaranteed by ETO’s subsidiary, Sunoco Logistics Operations.
As of June 30, 2020, the ETO Term Loan had $2 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of June 30, 2020 was 1.18%.
ETO Five-Year Credit Facility
Indebtedness under the Parent Company Credit Facility is secured by all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, but is not guaranteed by any of the Parent Company’s subsidiaries.
On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the Revolver Lenders have committed to provide advances up to an aggregate principal amount of $1.5 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit. Under the

Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of September 30, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $309 million.
ETLP Credit Facility
The ETLP Credit Facility allows for borrowings of up to $3.75 billion and matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of September 30, 2017, the ETLP Credit Facility had $2.06 billion of outstanding borrowings, all of which was commercial paper.
Sunoco Logistics Credit Facilities
ETP maintains the Sunoco Logistics $2.50 billion unsecuredETO’s revolving credit facility (the “Sunoco Logistics“ETO Five-Year Credit Facility”), which allows for unsecured borrowings up to $5.00 billion and matures in March 2020.on December 1, 2023. The Sunoco LogisticsETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $3.25$6.00 billion under certain conditions.
As of SeptemberJune 30, 2017,2020, the Sunoco LogisticsETO Five-Year Credit Facility had $35 million$3.01 billion of outstanding borrowings.borrowings, $1.11 billion of which was commercial paper. The amount available for future borrowings was $1.90 billion, after taking into account letters of credit of $86 million. The weighted average interest rate on the total amount outstanding as of June 30, 2020 was 1.34%.
In December 2016, Sunoco Logistics entered into an agreement for aETO 364-Day Facility
ETO’s 364-day maturityrevolving credit facility (“(the “ETO 364-Day Credit Facility”), due allows for unsecured borrowings up to mature$1.00 billion and matures on November 27, 2020. As of June 30, 2020, the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, theETO 364-Day Credit Facility was terminated and repaid in May 2017.had no outstanding borrowings.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit agreement,facility (the “Sunoco LP Credit Facility”), which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility.July 2023. As of SeptemberJune 30, 2017,2020, the Sunoco LP credit facilityCredit Facility had $644$158 million of outstanding borrowings and $19$8 million in standby letters of credit. As of June 30, 2020, Sunoco LP had $1.33 billion of availability under the Sunoco LP Credit Facility. The unused availabilityweighted average interest rate on the revolver at Septembertotal amount outstanding as of June 30, 20172020 was $847 million.2.19%.
BakkenUSAC Credit Facility
In August 2016, ETP, Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50USAC maintains a $1.60 billion revolving credit facility provides substantially all(the “USAC Credit Facility”), with a further potential increase of the remaining capital necessary to complete the projects.$400 million, which matures in April 2023. As of SeptemberJune 30, 2017, $2.52020, the USAC Credit Facility had $448 million of outstanding borrowings and no outstanding letters of credit. As of June 30, 2020, USAC had $1.15 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $151 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of June 30, 2020 was outstanding under this2.77%.
SemCAMS Credit Facilities
SemCAMS is party to a credit facility.
PennTex Revolving Credit Facility
PennTex previously maintainedagreement providing for a $275 C$350 million (US$257 million at theJune 30, 2020exchange rate) senior secured term loan facility, a C$525 million (US$385 million at the June 30, 2020exchange rate) senior secured revolving credit commitmentfacility, and a C$300 million (US$220 million at theJune 30, 2020exchange rate) senior secured construction loan facility (the “PennTex Revolving Credit“KAPS Facility”). In August 2017,The term loan facility and the PennTex Revolving Creditrevolving credit facility mature on February 25, 2024. The KAPS Facility was repaidmatures on June 13, 2024. SemCAMS may incur additional term loans and terminated.revolving commitments in an aggregate amount not to exceed C$250 million (US$183 million at the June 30, 2020exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.As of June 30, 2020, the SemCAMS senior secured term loan facility and senior secured revolving credit facility had $251 million and $92 million, respectively, of outstanding borrowings. As of June 30, 2020, the KAPS Facility hadnooutstanding borrowings.
Covenants Related to Our Credit Agreements
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective creditdebt agreements as of SeptemberJune 30, 2017.2020.

CASH DISTRIBUTIONS
Cash Distributions Paid by the Parent Company
Under the Parent Company Partnership Agreement,partnership agreement, the Parent Company will distribute all of its Available Cash, as defined in the partnership agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at

the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partnerour general partner that is necessary or appropriate to provide for future cash requirements.
Following are distributionsDistributions declared and/or paid by us subsequent to December 31, 2016:
Quarter Ended Record Date Payment Date Rate
    
December 31, 2016 (1)
 February 7, 2017 February 21, 2017 $0.2850
March 31, 2017 (1)
 May 10, 2017 May 19, 2017 0.2850
June 30, 2017 (1)
 August 7, 2017 August 21, 2017 0.2850
September 30, 2017 November 7, 2017 November 20, 2017 0.2950
(1)
Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note 9, ETE Series A Convertible Preferred Units.
Our distributions declared with respect to our Convertible Units during the year ended December 31, 20162019 were as follows:
Quarter Ended          Record Date Payment Date  Rate
December 31, 2016 February 7, 2017 February 21, 2017 $0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100
The total amounts of distributions declared for the periods presented (all from Available Cash from operating surplus and are shown in the period with respect to which they relate):
 Nine Months Ended
September 30,
 2017 2016
Limited Partners$757
 $721
General Partner interest2
 2
Total Parent Company distributions$759
 $723
Cash Distributions Received by the Parent Company
The Parent Company’s cash available for distributions historically has been primarily generated from its direct and indirect interests in ETP and Sunoco LP. Lake Charles LNG also contributes to the Parent Company’s cash available for distributions.
As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.

Percentage of Total Distributions to IDRsQuarterly Distribution Rate Target Amounts
Minimum quarterly distribution—%$0.075
First target distribution—%$0.075 to $0.0833
Second target distribution13%$0.0833 to $0.0958
Third target distribution35%$0.0958 to $0.2638
Fourth target distribution48%Above $0.2638
The total amount of distributions to the Parent Company from its limited partner interests, general partner interest and incentive distributions (shown in the period to which they relate) for the periods ended as noted below is as follows:
 Nine Months Ended
September 30,
 2017 2016
Distributions from ETP:   
Limited Partner interests$45
 $8
Class H Units—
 263
General Partner interest12
 24
IDRs1,204
 1,012
IDR relinquishments net of Class I Unit distributions(482) (271)
Total distributions from ETP779
 1,036
Distributions from Sunoco LP   
Limited Partner interests6
 6
IDRs63
 60
Series A Preferred15
 —
Total distributions from Sunoco LP84
 66
Total distributions received from subsidiaries863
 1,102
ETE has agreed to relinquish its right to the following amounts of incentive distributions from the ETP in future periods:
  Total Year
2017 (remainder) $173
2018 153
2019 128
Each year beyond 2019 33
ETE may agree to relinquish its rights to additional amounts of incentive distributions in future periods. Please see “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016. ETE may agree to relinquish its rights to a portion of its incentive distributions in future periods without the consent of ETE unitholders.
Quarter Ended Record Date Payment Date Rate
December 31, 2019 February 7, 2020 February 19, 2020 $0.3050
March 31, 2020 May 7, 2020 May 19, 2020 0.3050
June 30, 2020 August 7, 2020 August 19, 2020 0.3050
Cash Distributions Paid by Subsidiaries
Certain of our subsidiariesETO, Sunoco LP and USAC are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.
Cash Distributions Paid by ETPETO
Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the ETP’s limited partnership, which was Sunoco Logistics’ limited partnership agreement prior to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, ETP distributes all cashDistributions on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as "available cash" in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP's business. ETP will

make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
The following table shows the target distribution levels and distribution "splits" between the general partner and the holders of ETP common units:
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount IDRs 
Partners (1)
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%
(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
For the quarter ended December 31, 2016, Energy Transfer Partners, L.P. and Sunoco Logistics paid distributions on February 14, 2017 of $0.7033 and $0.52, respectively, per common unit.
Following are distributionsETO preferred units declared and/or paid by ETPETO subsequent to the Sunoco Logistics Merger:December 31, 2019 were as follows:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 15, 2017 $0.5350
June 30, 2017 August 7, 2017 August 14, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
Period Ended Record Date Payment Date 
Series A (1)
 
Series B (1)
 Series C Series D Series E 
Series F (2)
 
Series G (2)
December 31, 2019 February 3, 2020 February 18, 2020 $31.25
 $33.125
 $0.4609
 $0.4766
 $0.4750
 $—
 $—
March 31, 2020 May 1, 2020 May 15, 2020 —
 —
 0.4609
 0.4766
 0.4750
 21.19
 22.36
June 30, 2020 August 3, 2020 August 17, 2020 31.25
 33.125
 0.4609
 0.4766
 0.4750
 —
 —
The total amount of distributions declared during the periods presented were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):
 Nine Months Ended
September 30,
 2017 2016
 ETP Energy Transfer Partners, L.P. Sunoco Logistics
Limited Partners:     
Common Units held by public$1,794
 $1,607
 $353
Common Units held by ETP—
 —
 100
Common Units held by ETE45
 8
 —
Class H Units held by ETE—
 263
 —
General Partner interest12
 24
 11
Incentive distributions held by ETE1,204
 1,012
 289
IDR relinquishments(482) (271) (8)
Total distributions declared to partners$2,573
 $2,643
 $745

(1)
ETOSeries A Preferred Unit and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.
(2)
ETO Series F and G Preferred Unit distributions related to the period ended March 31, 2020 represent a prorated initial distribution. Distributions are paid on a semi-annual basis.
Cash Distributions Paid by Sunoco LP
Following are distributionsDistributions declared and/or paid by Sunoco LP to its common unitholders subsequent to December 31, 2016:2019 were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2016 February 13, 2017 February 21, 2017 $0.8255
March 31, 2017 May 9, 2017 May 16, 2017 0.8255
June 30, 2017 August 7, 2017 August 15, 2017 0.8255
September 30, 2017 November 7, 2017 November 14, 2017 0.8255
Quarter Ended Record Date Payment Date Rate
December 31, 2019 February 7, 2020 February 19, 2020 $0.8255
March 31, 2020 May 7, 2020 May 19, 2020 0.8255
June 30, 2020 August 7, 2020 August 19, 2020 0.8255
The total amounts of Sunoco LP distributionsCash Distributions Paid by USAC
Distributions declared for the periods presented (all from Available Cash from Sunoco LP’s operating surplus and are shown in the period with respectand/or paid by USAC to which they relate):its common unitholders subsequent to December 31, 2019 were as follows:
 Nine Months Ended
September 30,
 2017 2016
Limited Partners:   
Common units held by public$133
 $122
Common and subordinated units held by ETP150
 107
Common and subordinated units held by ETE6
 6
General Partner interest and Incentive distributions63
 60
Series A Preferred15
 —
Total distributions declared$367
 $295
Quarter Ended Record Date Payment Date Rate
December 31, 2019 January 27, 2020 February 7, 2020 $0.5250
March 31, 2020 April 27, 2020 May 8, 2020 0.5250
June 30, 2020 July 31, 2020 August 10, 2020 0.5250

ESTIMATES AND CRITICAL ACCOUNTING POLICIES
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. We describe our significant accounting policies in Note 2 to our consolidated financial statements in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 21, 2020. See Note 1 in “Item 1. Financial Statements” for information regarding recent changes to the Partnership’s critical accounting policies have not changed subsequent to those reported in Exhibit 99.1 to its Form 8-K filed on October 2, 2017. The following information is provided to supplement those disclosures specifically related to impairment of long-lived assets and goodwill.inventory.
Impairment of Long-Lived Assets and Goodwill.  During the three months ended June 30, 2017, Sunoco LP announced the sale of a majority of the assets in its retail reporting unit. Sunoco LP’s retail reporting unit includes the retail operations in the continental United States but excludes the retail convenience store operations in Hawaii that comprise the Aloha reporting unit. Upon the classification of assets and related liabilities as held for sale, Sunoco LP’s management applied the measurement guidance in ASC 360, Property, Plant and Equipment, to calculate the fair value less cost to sell of the disposal group. In accordance with ASC 360-10-35-39, management first tested the goodwill included within the disposal group for impairment prior to measuring the disposal group’s fair value less the cost to sell. In the determination of the classification of assets held for sale and the related liabilities, management allocated a portion of the goodwill balance previously included in the Sunoco LP retail reporting unit to assets held for sale based on the relative fair values of the business to be disposed of and the portion of the reporting unit that will be retained in accordance with ASC 350-20-40-3. The amount of goodwill allocated to assets held for sale was approximately $1.6 billion, and the amount of goodwill allocated to the remainder of the retail reporting unit, which is comprised of Sunoco LP’s ethanol plant, credit card processing services and franchise royalties, was approximately $188 million.RECENT ACCOUNTING PRONOUNCEMENTS
Once the retail reporting unit’s goodwill was allocated between assets held for sale and continuing operations, management performed goodwill impairment tests on both reporting units to which the goodwill balances were allocated. No goodwill impairment was identified for the $188 million goodwill balance that remained in the retail reporting unit. The result of the impairment test of the goodwill included within the assets held for sale initially indicated an impairment charge of $320 million, which was recognized during the three months ended June 30, 2017. Subsequent to June 30, 2017, management continued to evaluate the goodwill for impairment based on additional information on the fair value of the reporting unit, which resulted in an additional impairment of $44 million during the three months ended September 30, 2017. The key assumption in the impairment test for the goodwill balance classified as held for sale was the fair value of the disposal group, which was based on the assumed proceeds from the sale of those assets. The announced purchase and sale agreement includes the majority of the retail sitesCurrently, there are no accounting pronouncements that have been classifiedissued, but not yet adopted, that are expected to have a material impact on the Partnership’s financial position or results of operations.
FORWARD-LOOKING STATEMENTS
This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as held for sale; thus, a key assumption in the goodwill impairment test was the assumed sales proceeds (less the related costswell as assumptions made by and information currently available to sell) for the remainder of the sites, which represent approximately 15% of the total number of sites. Management is currently marketing the remaining sites for sale and utilized information fromus. These forward-looking statements are identified as any statement that sales processdoes not relate strictly to develop the assumed sales proceeds for those sites. While management believes that the assumed sales proceeds for these remaining held-for-sale sites are

reasonable and likely to be obtained in a sale of those sites, an agreement has not been negotiated and therefore the ultimate outcome could be different than the assumptionhistorical or current facts. When used in the impairment test. Subsequentthis annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to the impairment of goodwill included within the assets held for sale, no further impairments of any other assets held for sale were deemed necessary as the remaining carrying value of the disposal group approximated the assumed proceeds from the sale of those assets less the cost to sell.
For goodwill included in the Alohaidentify forward-looking statements. Although we and Wholesale reporting units, which goodwill balances total $112 million and $732 million, respectively, and which were not classified as held for sale, no impairments were deemed necessary during the three months ended June 30, 2017. Management does notour General Partner believe that the goodwill associated with eitherexpectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these reporting unitsrisks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the remaining goodwillkey risk factors that may have a direct bearing on our results of $188 million withinoperations and financial condition are:
•
changes in the long-term supply of and demand for natural gas, NGLs, refined products and/or crude oil, including as a result of uncertainty regarding the length of time it will take for the United States and the rest of the world to slow the spread of the COVID-19 virus to the point where applicable authorities are comfortable easing current restrictions on various commercial and economic activities; such restrictions are designed to protect public health but also have the effect of reducing demand for natural gas, NGLs, refined products and crude oil;
•
the severity and duration of world health events, including the recent COVID-19 pandemic, related economic repercussions, actions taken by governmental authorities and other third parties in response to the pandemic and the resulting severe disruption in the oil and gas industry and negative impact on demand for natural gas, NGLs, refined products and crude oil, which may negatively impact our business;
•
changes in general economic conditions and changes in economic conditions of the crude oil and natural gas industries specifically, including the current significant surplus in the supply of oil and actions by foreign oil-producing nations with respect to oil production levels and announcements of potential changes in such levels, including the ability of those countries to agree on and comply with supply limitation;
•
uncertainty regarding the timing, pace and extent of an economic recovery in the United States and elsewhere, which in turn will likely affect demand for natural gas, NGLs, refined products and crude oil and therefore the demand for midstream services we provide and the commercial opportunities available to us;
•
the deterioration of the financial condition of our customers and the potential renegotiation or termination of customer contracts as a result of such deterioration;
•
operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;
•
actions taken by federal, state or local governments to require producers of natural gas, NGL, refined products and crude oil to proration or cut their production levels as a way to address any excess market supply situations;
•
the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;
•
the actual amount of cash distributions by our subsidiaries to us;

•
the volumes transported on our subsidiaries’ pipelines and gathering systems;
•
the level of throughput in our subsidiaries’ processing and treating facilities;
•
the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;
•
the prices and market demand for, and the relationship between, natural gas and NGLs;
•
energy prices generally;
•
the prices of natural gas and NGLs compared to the price of alternative and competing fuels;
•
the general level of petroleum product demand and the availability and price of NGL supplies;
•
the level of domestic natural gas, NGL, refined products and crude oil production;
•
the availability of imported natural gas, NGLs, refined products and crude oil;
•
actions taken by foreign oil and gas producing nations;
•
the political and economic stability of petroleum producing nations;
•
the effect of weather conditions on demand for natural gas, NGLs, refined products and crude oil;
•
availability of local, intrastate and interstate transportation systems;
•
the continued ability to find and contract for new sources of natural gas supply;
•
availability and marketing of competitive fuels;
•
the impact of energy conservation efforts;
•
energy efficiencies and technological trends;
•
governmental regulation and taxation;
•
changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;
•
hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
•
competition from other midstream companies and interstate pipeline companies;
•
loss of key personnel;
•
loss of key natural gas producers or the providers of fractionation services;
•
reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities;
•
the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments;
•
the nonpayment or nonperformance by our subsidiaries’ customers;
•
regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries' internal growth projects, such as our subsidiaries' construction of additional pipeline systems;
•
risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries' existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;
•
the availability and cost of capital and our subsidiaries' ability to access certain capital sources;
•
a deterioration of the credit and capital markets;
•
risks associated with the assets and operations of entities in which our subsidiaries own less than a controlling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;
•
the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;
•
changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

•
the costs and effects of legal and administrative proceedings.
Many of the retail reporting unitforegoing risks and uncertainties are, and will be, heightened by the COVID-19 pandemic and any further worsening of the global business and economic environment. New factors emerge from time to time, and it is at significant risknot possible for us to predict all such factors. Should one or more of impairment,the risks or uncertainties described in this Quarterly Report on Form 10-Q or our Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the goodwill will continuerisks described under “Part I - Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019, “Part II - Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and “Part II - Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be subjectedmade from time to annual goodwill impairment testing on October 1.time, whether as a result of new information, future developments or otherwise.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in ourthe Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016,2019 filed with the SEC on February 21, 2020, in addition to the accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2016.2019. Since December 31, 2016,2019, there have been no material changes to our primary market risk exposures or how those exposures are managed.

Commodity Price Risk
The table below summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power and barrels for natural gas liquids, crude and refined products. Dollar amounts are presented in millions.

September 30, 2017 December 31, 2016June 30, 2020 December 31, 2019
Notional
Volume
 
Fair Value
Asset
(Liability)
 
Effect of
Hypothetical
10% Change
 
Notional
Volume
 
Fair Value
Asset
(Liability)
 
Effect of
Hypothetical
10% Change
Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change
Mark-to-Market Derivatives                      
(Trading)                      
Natural Gas (MMBtu):           
Natural Gas (BBtu):           
Basis Swaps IFERC/NYMEX (1)
(20,433) $10
 $4
 (35,208) $2
 $5
Fixed Swaps/Futures1,297,500
 $—
 $—
 (682,500) $—
 $—
373
 —
 —
 1,483
 —
 —
Basis Swaps IFERC/NYMEX (1)
(15,810,000) (4) —
 2,242,500
 (1) —
Options – Puts13,000,000
 —
 —
 —
 —
 —
Power (Megawatt):                      
Forwards665,040
 1
 2
 391,880
 (1) 1
1,338,776
 4
 3
 3,213,450
 6
 8
Futures(213,840) —
 1
 109,564
 —
 —
204,090
 —
 1
 (353,527) 1
 2
Options — Puts(280,800) 1
 2
 (50,400) —
 —
Options — Calls545,600
 —
 1
 186,400
 1
 —
Crude (Bbls):           
Futures(160,000) 1
 1
 (617,000) (4) 6
Options – Puts(340,743) 1
 —
 51,615
 1
 —
Options – Calls(1,268,532) 1
 —
 (2,704,330) 1
 —
(Non-Trading)                      
Natural Gas (MMBtu):           
Natural Gas (BBtu):           
Basis Swaps IFERC/NYMEX67,500
 (3) 2
 10,750,000
 2
 —
(27,713) 19
 8
 (18,923) (35) 15
Swing Swaps IFERC91,897,500
 (2) —
 (5,662,500) (1) 1
(35,590) (3) 8
 (9,265) —
 4
Fixed Swaps/Futures(20,220,000) 1
 7
 (52,652,500) (27) 19
(10,708) (20) 20
 (3,085) (1) 1
Forward Physical Contracts(140,937,993) 3
 43
 (22,492,489) 1
 —
(23,980) 6
 6
 (13,364) 3
 3
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps(8,744,200) (48) 80
 (5,786,627) (40) 35
Refined Products (Bbls) — Futures(1,947,000) 1
 19
 (3,144,000) (21) 18
Corn (Bushels) — Futures650,000
 —
 —
 1,580,000
 —
 1
NGLs (MBbls) – Forwards/Swaps(8,830) (10) 20
 (1,300) (18) 18
Refined Products (MBbls) – Futures(3,370) (17) 1
 (2,473) (2) 16
Crude (MBbls) – Forwards/Swaps3,393
 2
 —
 4,465
 13
 2
Corn (thousand bushels)—
 —
 —
 (1,210) —
 —
Fair Value Hedging Derivatives                      
(Non-Trading)                      
Natural Gas (MMBtu):           
Natural Gas (BBtu):           
Basis Swaps IFERC/NYMEX(41,102,500) 2
 —
 (36,370,000) 2
 1
(43,235) —
 10
 (31,780) 1
 7
Fixed Swaps/Futures(41,102,500) 5
 12
 (36,370,000) (26) 14
(43,235) (4) 11
 (31,780) 23
 7
(1) 
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
The fair values of the commodity-related financial positions have been determined using independent third partythird-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.
Interest Rate Risk
As of SeptemberJune 30, 2017,2020, we and our subsidiaries had $10.47$6.78 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $105$68 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We

manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding (dollars in millions), none of which are designated as hedges for accounting purposes:
    Notional Amount Outstanding
Term 
Type(1)
 September 30, 2017 December 31, 2016
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
Term 
Type(1)
 Notional Amount Outstanding
June 30,
2020		 December 31,
2019
July 2020(2)(3)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate $—
 $400
July 2021(2)
 Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400
 400
July 2022(2)
 Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400
 400
(1) 
Floating rates are based on 3-month LIBOR.
(2) 
Represents the effective date. These forward-starting swaps have a termterms of 30 years with a mandatory termination date the same as the effective date.
(3)
The July 2020 interest rate swaps were terminated in January 2020.
A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains and losses on interest rate derivatives) of $237$311 million as of SeptemberJune 30, 2017. For ETP’s $1.50 billion of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $19 million.2020. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Under the supervision and with the participation of senior management, including the PresidentChief Executive Officer (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of SeptemberJune 30, 20172020 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
ThereDuring thethree months endedJune 30, 2020, certain of the Partnership’s subsidiaries implemented an enterprise resource planning (“ERP”) system, in order to update existing technology and to integrate, simplify and standardize processes among the Partnership and its subsidiaries. Accordingly, we have made changes to our internal controls to address systems and/or processes impacted by the ERP implementation. Neither the ERP implementation nor the related control changes were undertaken in response to any deficiencies in the Partnership’s internal control over financial reporting.
Other than as discussed above, there have been no changes in our internal controls other than those discussed above, over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during thethree months ended SeptemberJune 30, 2017 2020that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.


PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see our Annual Report on Form 10-K forfiled with the year ended December 31, 2016SEC on February 21, 2020 and Note 1110 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Equity, L.P.LP and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended SeptemberJune 30, 2017.2020.

The EPA has brought aAdditionally, we have received notices of violations and potential fines under various federal, court action against SPLPstate and Mid-Valley for violationslocal provisions relating to the discharge of materials into the environment or protection of the Clean Water Act (“CWA”). The United States’ complaint allegesenvironment. While we believe that SPLP and Mid-Valley violated Sections 311(b)(7)(A) and 301(a)even if any one or more of the CWA when, during three separate releases, pipelines operated by SPLP and owned by SPLPenvironmental proceedings listed below were decided against us, it would not be material to our financial position, results of operations or Mid-Valley Pipeline Company discharged oil. See 33 U.S.C. §§ 1311(a) and 1321(b)(7)(A). In particular,cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $100,000.
Pursuant to the three releases at issue occurred (1) on February 23, 2013,instructions to Form 10-Q, matters disclosed in Tyler County, Texas, when a reported 550 barrels of oil were discharged; (2) on October 13, 2014, in Caddo Parish, Louisiana, when a reported 4,509 barrels of oil were discharged; and (3) on January 20, 2015, in Grant County, Oklahoma, when a reported 40 barrels of oil were discharged.  Potential fines from the DOJ are $7 million and from the State of Louisiana are approximately $1 million. The Partnership is currently in discussions to resolve these matters.
Mont Belvieu received a Notice of Enforcement (“NOE”) with an Agreed Order from the Texas Commission on Environmental Quality andthis Part II - Item 1 include any reportable legal proceeding (i) that has a pending settlement for $0.01 million.  The NOE was for the two violations.
Energy Transfer Company Field Services, LLC received a settlement agreement and a stipulated final compliance order from the New Mexico Environmental Department (“NMED”) on October 12, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. This order is a combination of Notice of Violation REG-0569-1402-R1 and Notice of Violation REG-0569-1601. The alleged violations occurred during the periods of March 24, 2014 through September 30, 2014 and September 1, 2016 through December 31, 2016. The settlement includes a civil penalty in the amount of $0.4 million and a supplement environmental project in the amount of $0.8 million.
Energy Transfer Company Field Services, LLC received a settlement offer from the NMED on June 6, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. The alleged violation occurredbeen terminated during the period of January 1, 2017 through September 11, 2017. The NMED is offering to settlecovered by this report, (ii) that became a reportable event during the violations with a civil penalty of $0.6 million.
On July 14, 2017, Sunoco LP’s subsidiary Aloha Petroleum, Ltd. (“Aloha”) received a Notice of Violation and Order (“NOVO”) from the Hawaii Department of Health (“DOH”) relating to alleged leak detection and reporting deficiencies at Aloha’s AIM Diamond Head facility in Honolulu, Hawaii with proposed civil penalties of $0.2 million. Aloha is in discussions with the DOH regarding the NOVO. The timingperiod covered by this report, or outcome of this matter cannot reasonably be determined at this time however, the Partnership does not expect(iii) for which there to behas been a material impact ondevelopment during the period covered by this report.
For a description of other legal proceedings, see Note 10 to our business or results of operations.consolidated financial statements included in “Item 1. Financial Statements.”
ITEM 1A. RISK FACTORS
There have been no material changes from theThe following risk factors should be read in conjunction with our risk factors described in “Part"Part I —- Item 1A. Risk Factors” of ourFactors" in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2016 or2019 filed with the SEC on February 21, 2020 and from the risk factors described in “Part"Part II —- Item 1A. Risk Factors” of ourFactors" in the Partnership's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.2020 filed with the SEC on May 11, 2020.
Legal or regulatory actions related to the Dakota Access Pipeline could cause an interruption to current or future operations, which could have an adverse effect on our business and results of operations.
On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia challenging permits issued by the United States Army Corps of Engineers (“USACE”) permitting Dakota Access, LLC (“Dakota Access”) to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE allowing the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively with SRST and CRST, the “Tribes”). Plaintiffs and Defendants filed cross motions for summary judgment. On March 25, 2020, the Court remanded the case back to the USACE for preparation of an Environment Impact Statement. On July 6, 2020, the Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and USACE have filed notices of appeal with the United States Court of Appeals for the District of Columbia (“Court of Appeals”) with respect to the Court’s ruling related to the preparation of an Environmental Impact Statement and also filed motions for a stay of the Court’s July 6, 2020 Order. On July 14, 2020, the Court of Appeals administratively stayed the Court’s July 6 Order and ordered further briefing with respect to the motion to stay. On August 5, 2020, the Court of Appeals granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil. The Court of Appeals also denied a stay of the March 25 Order and the remaining portion of the July 6 Order vacating the easement. As a result, no court order stops Dakota Access from continuing to operate the Pipeline. The August 5 Order contemplates that the USACE will make a determination under its regulations and procedures whether vacating the easement requires oil to stop flowing. The Order also contemplates further proceedings in the District Court, and it expedites the appeal with briefing to conclude by September 30, 2020.
While we believe that the pending lawsuits are unlikely to adversely affect the continued operation or potential expansion of the pipeline, we cannot assure this outcome. At this time, we cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.

ITEM 6. EXHIBITS
The exhibits listed below are filed or furnished, as indicated, as part of this report:
Exhibit Number Description
12.1*
3.1		 
ComputationCertificate of RatioLimited Partnership of EarningsEnergy Transfer Equity, L.P. (incorporated by reference to Fixed Charges.Exhibit 3.2 of Form S-1, File No. 333-128097, filed September 2, 2005)
31.1*
3.2		 
Certificate of Amendment of Certificate of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed October 19, 2018)
3.3
Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed February 14, 2006)
3.4
Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 of Form 10-K, File No. 1-32740, filed November 29, 2006)
3.5
Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 of Form 8-K, File No. 1-32740, filed November 13, 2007)
3.6
Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed June 2, 2010)
3.7
Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed December 27, 2013)
3.8
Amendment No. 5 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated March 8, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed March 9, 2016)
3.9
Amendment No. 6 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.9 of Form 10-Q, File No. 1-32740, filed November 8, 2018)
3.10
Amendment No. 7 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP dated as of August 6, 2019 (incorporated by reference to Exhibit 3.10 of Form 10-Q, File No. 1-32740, filed August 8, 2019)
31.1*
Certification of PresidentChief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002
31.2*
 
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002
32.1**
 
Certification of PresidentChief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002
32.2**
 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002
101.INS*101* XBRL Instance DocumentInteractive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019; (ii) our Consolidated Statements of Operations for the three and six months ended June 30, 2020 and 2019; (iii) our Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2020 and 2019; (iv) our Consolidated Statements of Partners’ Capital for the three and six months ended June 30, 2020 and 2019; (v) our Consolidated Statements of Cash Flows for the six months ended June 30, 2020 and 2019; and (vi) the notes to our Consolidated Financial Statements.
101.SCH*104 Cover Page Interactive Data File (formatted as inline XBRL Taxonomy Extension Schema Document
101.CAL*XBRL Taxonomy Calculation Linkbase Document
101.DEF*XBRL Taxonomy Extension Definitions Document
101.LAB*XBRL Taxonomy Label Linkbase Document
101.PRE*XBRL Taxonomy Presentation Linkbase Documentand contained in Exhibit 101)
* Filed herewith.
** Furnished herewith.


SIGNATURE
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.
  ENERGY TRANSFER EQUITY, L.P.LP
    
  By: LE GP, LLC, its General Partnergeneral partner
    
Date:November 7, 2017August 6, 2020By: /s/ Thomas E. LongA. Troy Sturrock
    Thomas E. LongA. Troy Sturrock
    
Group Chief FinancialSenior Vice President, Controller and Principal Accounting Officer (duly
authorized to sign on behalf of the registrant)



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