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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, 20172019
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,August 2, 2019, the registrant had 1,079,185,0302,623,235,994 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
4
  
Consolidated Statement of Equity
5
  
Consolidated Statements of Cash Flows
6
Notes to Consolidated Financial Statements
7
  
Notes to Consolidated Financial Statements
8
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
4246
  
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
5971
  
ITEM 4. CONTROLS AND PROCEDURES
6172
  
PART II — OTHER INFORMATION
 
  
ITEM 1. LEGAL PROCEEDINGS
6174
  
ITEM 1A. RISK FACTORS
6275
  
ITEM 6. EXHIBITS5. OTHER INFORMATION
6275
  
SIGNATUREITEM 6. EXHIBITS
6376
SIGNATURE
77




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Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as somecertain statements by Energy Transfer LP, formerly Energy Transfer Equity, L.P. (“Energy Transfer, Equity”” the “Partnership” or “ETE”“ET”), in periodic press releases and somecertain oral statements of Energy Transfer Equity officialsmanagement during presentations about 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 Annual Report on Form 10-K for the year ended December 31, 20162018 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, 2017.22, 2019.
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
    
 CDMCDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively
CitrusCitrus, LLC, which owns 100% of FGT
DOJ U.S. Department of Justice
    
 EPA U.S. Environmental Protection Agency
    
 ETLP Credit FacilityETC Sunoco Energy Transfer, LP’s $3.75 billion revolving credit facilityETC Sunoco Holdings LLC (formerly Sunoco, Inc.)
    
 ETPETO Energy Transfer Partners,Operating, L.P. subsequent to the close of the merger of Sunoco Logistics Partners L.P. and(formerly Energy Transfer Partners, L.P.)
    
 ETP GP Energy Transfer Partners GP, L.P., the general partner of ETPETO
    
 ETP HoldcoETO Series A Preferred Units ETP Holdco CorporationETO’s 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
    
 ETP LLCETO Series B Preferred Units Energy Transfer Partners, L.L.C., the general partner of ETP GPETO’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
    
 Exchange Act Securities Exchange Act of 1934
    
 FEPFayetteville Express Pipeline LLC
FERC Federal Energy Regulatory Commission
FGTFlorida Gas Transmission Company, LLC
    
 GAAP accounting principles generally accepted in the United States of America

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 IDRs incentive distribution rights
    
 Lake Charles LNG Lake Charles LNG Company, LLC
    
 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
    
 OSHA Federal Occupational Safety and Health Act
   
 OTC over-the-counter
    

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 Panhandle Panhandle Eastern Pipe Line Company, LP
   
PCBspolychlorinated biphenyl
 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
RIGSRegency Interstate Gas LP
    
 Rover Rover Pipeline LLC
    
 SEC Securities and Exchange Commission
    
 Series A Convertible Preferred Units ETEET Series A convertible preferred units
    
 Sunoco LogisticsSPLP Sunoco Logistics PartnersPipeline L.P.
    
 Sunoco LP Sunoco LP (previously named Susser Petroleum Partners, LP)
Sunoco LP Series A Preferred UnitsSunoco LP Series A Preferred Units previously held by ET
Sunoco R&MSunoco (R&M), LLC (formerly Sunoco, Inc. (R&M))
    
 Transwestern Transwestern Pipeline Company, LLC
    
 Trunkline Trunkline Gas Company, LLC
    
 WMBUSAC The Williams Companies, Inc.USA Compression Partners, LP
USAC Preferred UnitsUSAC Series A Preferred Units
Adjusted EBITDA is a term used throughout this document, which we define 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 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’sour 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, 2019 December 31, 2018
ASSETS      
Current assets:      
Cash and cash equivalents$469
 $463
$445
 $419
Accounts receivable, net3,551
 3,557
4,349
 4,009
Accounts receivable from related companies90
 47
111
 111
Inventories1,957
 2,103
1,832
 1,677
Derivative assets42
 21
54
 111
Income taxes receivable99
 73
Other current assets433
 503
308
 350
Current assets held for sale4,147
 291
Total current assets10,689
 6,985
7,198
 6,750
      
Property, plant and equipment68,730
 61,158
82,351
 79,776
Accumulated depreciation and depletion(9,463) (7,905)(14,164) (12,813)
59,267
 53,253
68,187
 66,963
      
Advances to and investments in unconsolidated affiliates3,177
 3,040
2,838
 2,642
Lease right-of-use assets, net853
 —
Other non-current assets, net891
 816
1,026
 1,006
Intangible assets, net6,195
 5,489
5,827
 6,000
Goodwill5,161
 5,170
4,883
 4,885
Non-current assets held for sale—
 4,258
Total assets$85,380
 $79,011
$90,812
 $88,246

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


September 30, 2017 December 31, 2016June 30, 2019 December 31, 2018
LIABILITIES AND EQUITY      
Current liabilities:      
Accounts payable$3,994
 $3,502
$3,645
 $3,493
Accounts payable to related companies46
 42
14
 59
Derivative liabilities129
 172
18
 185
Operating lease current liabilities59
 —
Accrued and other current liabilities2,881
 2,367
2,686
 2,918
Current maturities of long-term debt716
 1,194
7
 2,655
Liabilities associated with assets held for sale81
 —
Total current liabilities7,847
 7,277
6,429
 9,310
      
Long-term debt, less current maturities44,495
 42,608
46,499
 43,373
Long-term notes payable – related company—
 250
Non-current derivative liabilities132
 76
354
 104
Non-current operating lease liabilities803
 —
Deferred income taxes5,027
 5,112
3,071
 2,926
Other non-current liabilities1,218
 1,055
1,139
 1,184
Liabilities associated with assets held for sale—
 68
      
Commitments and contingencies
 

 

Preferred units of subsidiary—
 33
Redeemable noncontrolling interests21
 15
500
 499
      
Equity:      
General Partner(3) (3)
Limited Partners:      
Common Unitholders(1,566) (1,871)20,872
 20,606
Series A Convertible Preferred Units377
 180
Total partners’ deficit(1,192) (1,694)
Noncontrolling interest27,832
 24,211
General Partner(5) (5)
Accumulated other comprehensive loss(33) (42)
Total partners’ capital20,834
 20,559
Noncontrolling interests11,183
 10,291
Total equity26,640
 22,517
32,017
 30,850
Total liabilities and equity$85,380
 $79,011
$90,812
 $88,246

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

 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
REVENUES:       
Refined product sales$4,477
 $4,600
 $8,203
 $8,203
Crude sales4,346
 4,244
 7,871
 7,500
NGL sales1,996
 2,356
 4,398
 4,591
Gathering, transportation and other fees2,035
 1,667
 4,302
 3,097
Natural gas sales763
 1,024
 1,727
 2,086
Other260
 227
 497
 523
Total revenues13,877
 14,118
 26,998
 26,000
COSTS AND EXPENSES:       
Cost of products sold10,302
 11,343
 19,717
 20,588
Operating expenses792
 772
 1,600
 1,496
Depreciation, depletion and amortization785

694
 1,559
 1,359
Selling, general and administrative179
 183
 326
 331
Impairment losses—
 —
 50
 —
Total costs and expenses12,058
 12,992
 23,252
 23,774
OPERATING INCOME1,819
 1,126
 3,746
 2,226
OTHER INCOME (EXPENSE):       
Interest expense, net of interest capitalized(578) (510) (1,168) (976)
Equity in earnings of unconsolidated affiliates77
 92
 142
 171
Losses on extinguishments of debt—
 —
 (18) (106)
Gains (losses) on interest rate derivatives(122) 20
 (196) 72
Other, net46
 (1) 42
 56
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE1,242
 727
 2,548
 1,443
Income tax expense from continuing operations34
 68
 160
 58
INCOME FROM CONTINUING OPERATIONS1,208
 659
 2,388
 1,385
Loss from discontinued operations, net of income taxes—

(26) —
 (263)
NET INCOME1,208
 633
 2,388
 1,122
Less: Net income attributable to noncontrolling interests317
 278
 614
 404
Less: Net income attributable to redeemable noncontrolling interests13
 —
 26
 —
NET INCOME ATTRIBUTABLE TO PARTNERS878
 355
 1,748
 718
Series A Convertible Preferred Unitholders' interest in income—
 12
 —
 33
General Partner’s interest in net income1
 1
 2
 2
Limited Partners’ interest in net income$877
 $342
 $1,746
 $683
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:       
Basic$0.33
 $0.31
 $0.67
 $0.63
Diluted$0.33
 $0.31
 $0.66
 $0.63
NET INCOME PER LIMITED PARTNER UNIT:       
Basic$0.33
 $0.31
 $0.67
 $0.62
Diluted$0.33
 $0.31
 $0.66
 $0.62
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
REVENUES       
Natural gas sales$1,098
 $1,070
 $3,132
 $2,603
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
Total revenues9,474
 7,705
 27,637
 21,227
COSTS AND EXPENSES       
Cost of products sold7,078
 5,776
 21,028
 15,430
Operating expenses636
 526
 1,779
 1,540
Depreciation, depletion and amortization632

548
 1,840
 1,596
Selling, general and administrative142
 209
 484
 515
Total costs and expenses8,488
 7,059
 25,131
 19,081
OPERATING INCOME986
 646
 2,506
 2,146
OTHER INCOME (EXPENSE)       
Interest expense, net(505) (474) (1,471) (1,336)
Equity in earnings of unconsolidated affiliates92
 49
 228
 205
Impairment of investment in an unconsolidated affiliate—
 (308) —
 (308)
Losses on extinguishments of debt—
 —
 (25) —
Losses on interest rate derivatives(8) (28) (28) (179)
Other, net76
 55
 168
 98
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:       
Basic$0.22
 $0.20
 $0.64
 $0.72
Diluted$0.22
 $0.19
 $0.62
 $0.71
NET INCOME PER LIMITED PARTNER UNIT:       
Basic$0.22
 $0.20
 $0.63
 $0.72
Diluted$0.22
 $0.19
 $0.61
 $0.71


ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(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,
 2019 2018 2019 2018
Net income$1,208
 $633
 $2,388
 $1,122
Other comprehensive income, net of tax:       
Change in value of available-for-sale securities3
 —
 8
 (2)
Actuarial gain (loss) related to pension and other postretirement benefit plans3
 —
 10
 (2)
Change in other comprehensive income from unconsolidated affiliates(5) 2
 (9) 7
 1
 2
 9
 3
Comprehensive income1,209
 635
 2,397
 1,125
Less: Comprehensive income attributable to noncontrolling interests317
 280
 614
 407
Less: Comprehensive income attributable to redeemable noncontrolling interests13
 —
 26
 —
Comprehensive income attributable to partners$879
 $355
 $1,757
 $718

ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
FOR THE NINESIX MONTHS ENDED SEPTEMBERJUNE 30, 20172019 AND 2018
(Dollars in millions)
(unaudited)
 Common Unitholders     General Partner     AOCI Noncontrolling Interests Total   
Balance, December 31, 2018$20,606
 $(5) $(42) $10,291
 $30,850
Distributions to partners(799) (1) —
 —
 (800)
Distributions to noncontrolling interests—
 —
 —
 (425) (425)
Capital contributions received 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 interests869
 1
 —
 297
 1,167
Balance, March 31, 201920,693
 (5) (34) 10,408
 31,062
Distributions to partners(799) (1) —
 


 (800)
Distributions to noncontrolling interests—
 —
 —
 (388) (388)
Units issued51
 —
 —
 —
 51
Capital contributions received from noncontrolling interests—
 —
 —
 66
 66
Subsidiary units issued for cash—
 —
 —
 780
 780
Other comprehensive loss, net of tax—
 —
 1
 —
 1
Other, net50
 —
 —
 —
 50
Net income, excluding amounts attributable to redeemable noncontrolling interests877
 1
 —
 317
 1,195
Balance, June 30, 2019$20,872
 $(5) $(33) $11,183
 $32,017

General Partner     Common Unitholders     Series A Convertible Preferred Units Noncontrolling Interest Total    Series A Convertible Preferred Units Common Unitholders     General Partner     Noncontrolling Interests Total    
Balance, December 31, 2016$(3) $(1,871) $180
 $24,211
 $22,517
Balance, December 31, 2017$450
 $(1,643) $(3) $31,176
 $29,980
Distributions to partners(2) (750) —
 —
 (752)—
 (265) (1) —
 (266)
Distributions to noncontrolling interest—
 —
 —
 (2,180) (2,180)
Distributions to noncontrolling interests—
 —
 —
 (893) (893)
Distributions reinvested—
 (173) 173
 —
 —
58
 (58) —
 —
 —
Subsidiary units repurchased(6) (98) —
 80
 (24)
Subsidiary units issued—
 (56) (1) 1,692
 1,635
—
 1
 —
 19
 20
Issuance of common units—
 568
 —
 —
 568
Capital contributions received from noncontrolling interests—
 —
 —
 1,907
 1,907
—
 —
 —
 229
 229
PennTex unit acquisition—
 (2) —
 (278) (280)
Non-cash compensation expense, net of units tendered by employees for tax withholdings—
 —
 —
 69
 69
Sale of Bakken Pipeline interest—
 42
 —
 1,958
 2,000
Other comprehensive income, net of tax—
 —
 —
 6
 6
—
 —
 —
 1
 1
Cumulative effect adjustment due to change in accounting principle—
 —
 —
 (54) (54)
Other, net—
 —
 —
 (61) (61)(4) 26
 —
 (23) (1)
Net income2
 676
 25
 508
 1,211
21
 341
 1
 126
 489
Balance, September 30, 2017$(3) $(1,566) $377
 $27,832
 $26,640
Balance, March 31, 2018519
 (1,696) (3) 30,661
 29,481
Distributions to partners—
 (265) (1) —
 (266)
Distributions to noncontrolling interests—
 —
 —
 (900) (900)
Distributions reinvested57
 (57) —
 —
 —
Subsidiary units repurchased(1) (21) —
 22
 —
Subsidiary units issued—
 —
 —
 469
 469
Capital contributions received from noncontrolling interests—
 —
 —
 89
 89
Other comprehensive income, net of tax—
 —
 —
 2
 2
Acquisition of USAC—
 —
 —
 832
 832
Series A Convertible Preferred Units conversion(589) 589
 —
 —
 —
Other, net2
 2
 (1) 40
 43
Net income12
 342
 1
 278
 633
Balance, June 30, 2018$—
 $(1,106) $(4) $31,493
 $30,383

ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)
Nine Months Ended
September 30,		Six Months Ended
June 30,
2017 20162019 2018
OPERATING ACTIVITIES      
Net income$1,211
 $801
$2,388
 $1,122
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)
Loss from discontinued operations—
 263
Depreciation, depletion and amortization1,840
 1,596
1,559
 1,359
Deferred income taxes(120) (139)138
 71
Unit-based compensation expense76
 46
Inventory valuation adjustments(38) (203)(97) (57)
Non-cash compensation expense58
 55
Impairment losses50
 —
Loss on extinguishments of debt18
 106
Distributions on unvested awards(18) (25)
Equity in earnings of unconsolidated affiliates(228) (205)(142) (171)
Distributions from unconsolidated affiliates211
 190
170
 138
Other(134) (197)
Net change in operating assets and liabilities, net of effects of acquisition222
 48
Other non-cash44
 (56)
Net change in operating assets and liabilities, net of effects of acquisitions(274) 357
Net cash provided by operating activities3,304
 2,221
3,894
 3,162
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)
Cash proceeds from sale of noncontrolling interest in subsidiary93
 —
Cash proceeds from USAC acquisition, net of cash received—
 461
Cash paid for all other acquisitions, net of cash received(7) (143)
Capital expenditures, excluding allowance for equity funds used during construction(6,102) (5,877)(2,818) (3,539)
Contributions in aid of construction costs41
 60
Contributions to unconsolidated affiliates(230) (47)(254) (13)
Distributions from unconsolidated affiliates in excess of cumulative earnings115
 112
21
 31
Proceeds from the sale of other assets22
 6
Other30
 58
(40) —
Net cash used in investing activities(4,760) (6,084)(2,942) (3,137)
FINANCING ACTIVITIES      
Proceeds from borrowings23,988
 18,288
16,463
 16,702
Repayments of long-term debt(22,586) (13,955)
Cash received from affiliate notes—
 1,606
Cash paid on affiliate notes(255) (1,607)
Repayments of debt(15,925) (18,039)
Subsidiary units issued for cash1,635
 2,097
780
 940
Units issued for cash568
 —
Capital contributions from noncontrolling interests206
 318
Distributions to partners(752) (780)(1,549) (532)
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
Distributions to noncontrolling interests(813) (1,793)
Subsidiary repurchases of common units—
 (24)
Debt issuance costs(87) (173)
Other, net(1) 19
Net cash used in financing activities(926) (2,582)
DISCONTINUED OPERATIONS      
Operating activities245
 168
—
 (478)
Investing activities(82) (359)—
 3,207
Changes in cash included in current assets held for sale(4) 12
—
 11
Net increase (decrease) in cash and cash equivalents of discontinued operations159
 (179)
Increase (decrease) in cash and cash equivalents6
 (123)
Net increase in cash and cash equivalents of discontinued operations—
 2,740
Increase in cash and cash equivalents26
 183
Cash and cash equivalents, beginning of period463
 581
419
 336
Cash and cash equivalents, end of period$469
 $458
$445
 $519

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,October 2018, we completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). In connection with the transaction, ETO unitholders (other than ET and its subsidiaries) received 1.28 common units of ET for each common unit of ETO they owned. Following the closing of the Energy Transfer Merger, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquiredwas renamed Energy Transfer Partners,Operating, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary ofIn addition, Energy Transfer Partners,Equity, L.P. Under the terms of the transaction, the unitholders received 1.5was renamed Energy Transfer LP, and its 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. Basedbegan trading on the number of Energy Transfer Partners, L.P. common units outstanding atNew York Stock Exchange under the closing 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 time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of Energy Transfer Partners, L.P. units had immediately“ET” ticker symbol on October 19, 2018.
Immediately prior to the closing of the merger. Additionally,Energy Transfer Merger, the outstandingfollowing also occurred:
the IDRs in ETO were converted into 1,168,205,710 ETO common units;
the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued 18,448,341 ETO common units to ETP GP;
ET contributed its 2,263,158 Sunoco LogisticsLP common units to ETO in exchange for 2,874,275 ETO common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time100 percent of the merger were cancelled.limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units;
Prior to the Sunoco Logistics Merger, ETE owned 18.4 million Energy Transfer Partners, L.P.ET contributed its 12,466,912 common units (representing 3.3%representing limited partner interests in USAC and 100 percent of the total outstandinglimited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units), 81 million Energy Transfer Partners, L.P. Class H unitsunits; and
ET contributed its 100 Energy Transfer Partners, L.P. Class I units. In connection with the Sunoco Logistics Merger, the Class H units were cancelled,percent limited liability company interest in Lake Charles LNG 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 subsidiary60 percent limited liability company interest in each of Energy Transfer Partners, L.P. For purposesLNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC (collectively, “Lake Charles LNG and Other”) to ETO in exchange for 37,557,815 ETO common units.
Subsequent to the Energy Transfer Merger, substantially all of maintaining clarity,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. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein.
Our financial statements reflect the following referencesreportable 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 used herein:not separately reflected as reportable segments.
References to “ETLP” refer
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 included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on February 22, 2019. 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 entity named Energy Transfer, LP subsequent to the closerules and regulations 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, Energy Transfer Operating, L.P. (“ETO”); and
Energy Transfer Partners GP, L.P. (“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 in Energy Transfer Partners, L.L.C. (“ETP and Sunoco LP; and
our wholly-owned subsidiary, Lake Charles LNG.LLC”), the general partner of ETP GP.
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.
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 TransactionsChange in Accounting Policy
The Parent Company accounts for the difference between the carrying amountAdoption 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.Lease Accounting Standard
Recent Accounting Pronouncements
ASU 2014-09
In May 2014,February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers2016-02, Leases (Topic 606) (“ASU 2014-09”842), which has amended the FASB Accounting Standards Codification (“ASC”) and introduced Topic 842, Leases. On January 1, 2019, the Partnership has adopted ASC Topic 842 (“Topic 842”), which clarifies the principlesis effective for recognizing revenue basedinterim and annual reporting periods beginning on or after December 15, 2018. Topic 842 requires entities to recognize lease assets and liabilities on the core principlebalance sheet for all leases with a term of more than one year, including operating leases, which historically were not recorded on the balance sheet in accordance with the prior standard.
To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment to the opening balance sheet as of January 1, 2019 related to certain leases that an entity should recognize revenue to depict the transferexisted as 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,date. As permitted, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) may be impacted by thenot retrospectively modified our consolidated financial statements for comparative purposes. 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
On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not havehad a material impact on the Partnership’sour consolidated financial statements and related disclosures.
ASU 2016-16
In October 2016, 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 recognize the income tax consequences of an intra-entity transfer of an asset other 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

in the entity held through related parties 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 standardbalance sheet, but did not have an impact on our consolidated statements of operations, comprehensive income or cash flows. As a result of adoption, we have recorded additional net right-of-use (“ROU”) lease assets and lease liabilities of approximately $888 million and $888 million, respectively, as of January 1, 2019. In addition, we have updated our business processes, systems, and internal controls to support the Partnership’s consolidated financial statements and related disclosures.on-going reporting requirements under the new standard.
ASU 2017-04
In January 2017,To adopt Topic 842, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): SimplifyingPartnership elected the test for goodwill impairment.”package of practical expedients permitted under the transition guidance within the standard. The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value,expedient package allowed us not to exceedreassess whether existing contracts contained a lease, the total amountlease classification of goodwill allocatedexisting leases and initial direct cost for existing leases. In addition to the reporting unit. The new guidance doespackage of practical expedients, the Partnership has elected not amendto capitalize amounts pertaining to leases with terms less than twelve months, to use the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years,portfolio approach to determine discount rates, not to separate non-lease components from lease components 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 plansnot to apply this ASU for its annual goodwill impairment testthe use of hindsight to the active lease population.

Cumulative-effect adjustments made to the opening balance sheet at January 1, 2019 were as follows:
 Balance at December 31, 2018, as previously reported Adjustments due to Topic 842 (Leases) Balance at January 1, 2019
Assets:     
Property, plant and equipment, net$66,963
 $(1) $66,962
Lease right-of-use assets, net—
 889
 889
Liabilities:     
Operating lease current liabilities$—
 $71
 $71
Accrued and other current liabilities2,918
 (1) 2,917
Current maturities of long-term debt2,655
 1
 2,656
Long-term debt, less current maturities43,373
 6
 43,379
Non-current operating lease liabilities—
 823
 823
Other non-current liabilities1,184
 (12) 1,172
Additional disclosures related to lease accounting are included in the fourth quarter of 2017.Note 13.
Recent Accounting Pronouncements
ASU 2017-12
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. The Partnership adopted this guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years,the first quarter of 2019, and interim periods within those fiscal years, beginning after December 15, 2018, with earlythe adoption permitted. The Partnership is currently evaluating theof this guidance did not have a material impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
2.ACQUISITIONS AND DIVESTURESOTHER INVESTING TRANSACTIONS
Rover Contribution AgreementSunoco LP Retail Store and Real Estate Sales
In July 2017, ETP announced that it had entered into a contributionOn January 23, 2018, Sunoco LP completed the disposition of assets pursuant to the purchase 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”7-Eleven, Inc. (the “7-Eleven Transaction”). 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,the 7-Eleven Transaction, previously eliminated wholesale motor fuel sales to 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 LongviewLP’s retail locations are reported as wholesale motor fuel sales 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 onthird parties. Also, the related accounts receivable from such sales are no longer eliminated from the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assetssheets and $435 million of property, plant and equipment.are reported as accounts receivable.
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 isconnection with 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, 2017,7-Eleven Transaction, Sunoco LP entered into a definitive asset purchase agreementDistributor Motor Fuel Agreement dated as of January 23, 2018, as amended (“Supply Agreement”), with 7-Eleven and SEI Fuel (collectively, “Distributor”). The Supply Agreement consists of a 15-year take-or-pay fuel supply arrangement. For the period from January 1, 2018 through January 22, 2018, Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million, which were eliminated in consolidation. Sunoco LP received payments on trade receivables from 7-Eleven of $1.1 billion and $1.9 billion for the sale of a portfolio of approximately 1,112 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businessesthree and related assets, includingsix months ended June 30, 2019, respectively, and $979 million and $1.6 billion for the Laredo Taco Company,three and six months ended June 30, 2018, respectively, subsequent to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion (the “7-Eleven

Transaction”). Thethe 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 the financial position, results of operations and cash flows of Sunoco LP’s continental United States retail convenience storesdivestment 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
operations.

There were no results of operations associated with discontinued operations for the three and six months ended June 30, 2019. 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 and six months ended ended June 30, 2017 and $44 million recognized in the three months ended September 30, 2017.2018 were as follows:
 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
REVENUES$—
 $349
    
COSTS AND EXPENSES   
Cost of products sold—
 305
Operating expenses—
 61
Selling, general and administrative5
 7
Total costs and expenses5
 373
OPERATING LOSS(5) (24)
Interest expense, net—
 2
Loss on extinguishment of debt and other—
 20
Other, net38
 61
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)(43) (107)
Income tax expense (benefit)(17) 156
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES$(26) $(263)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ET$(1) $(10)

3. CASH AND CASH EQUIVALENTS
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.
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,
 2019 2018
Accounts receivable$(340) $253
Accounts receivable from related companies(1) 71
Inventories(57) 350
Other current assets30
 (370)
Other non-current assets, net(20) 69
Accounts payable199
 (600)
Accounts payable to related companies(49) (145)
Accrued and other current liabilities(89) 495
Other non-current liabilities(87) 1
Derivative assets and liabilities, net140
 233
Net change in operating assets and liabilities, net of effects of acquisitions$(274) $357
 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
 $—


4. INVENTORIESNon-cash activities are as follows:
 Six Months Ended
June 30,
 2019 2018
NON-CASH INVESTING ACTIVITIES:   
Accrued capital expenditures$714
 $1,015
Losses from subsidiary common unit transactions—
 (125)
Lease assets obtained in exchange for new lease liabilities15
 —
NON-CASH FINANCING ACTIVITIES:   
Distribution reinvestment$51
 $—
Conversion of Series A Convertible Preferred Units to common units—
 589

4.INVENTORIES
Inventories consisted of the following:
 June 30, 2019 December 31, 2018
Natural gas, NGLs and refined products$793
 $833
Crude oil622
 506
Spare parts and other417
 338
Total inventories$1,832
 $1,677

 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 its natural gas inventories stored in our Bammel storage facility.inventories. 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.
5. 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 SeptemberJune 30, 20172019 were $47.21$49.93 billion and $45.21$46.51 billion, respectively. As of December 31, 2016,2018, the aggregate fair value and carrying amount of our consolidated debt obligations were $45.05$45.06 billion and $43.80$46.03 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.
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, 2017,2019, no 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, 20172019 and December 31, 20162018 based on inputs used to derive their fair values:
  Fair Value Measurements at
September 30, 2017		  Fair Value Measurements at
June 30, 2019
Fair Value Total Level 1 Level 2Fair Value Total Level 1 Level 2
Assets:          
Commodity derivatives:          
Natural Gas:          
Basis Swaps IFERC/NYMEX16
 16
 —
$33
 $33
 $—
Swing Swaps IFERC2
 —
 2
Fixed Swaps/Futures28
 28
 —
35
 35
 —
Forward Physical Swaps3
 —
 3
Forward Physical Contracts7
 —
 7
Power:          
Forwards11
 —
 11
40
 —
 40
Futures1
 1
 —
7
 7
 —
Options — Puts1
 1
 —
Natural Gas Liquids – Forwards/Swaps213
 213
 —
Refined Products — Futures4
 4
 —
Crude – Futures2
 2
 —
NGLs – Forwards/Swaps377
 377
 —
Refined Products – Futures1
 1
 —
Crude – Forwards/Swaps40
 40
 —
Corn - Forwards/Swaps1
 1
 —
Total commodity derivatives281
 265
 16
541
 494
 47
Other non-current assets29
 19
 10
Total assets$281
 $265
 $16
$570
 $513
 $57
Liabilities:          
Interest rate derivatives$(210) $—
 $(210)$(354) $—
 $(354)
Commodity derivatives:          
Natural Gas:          
Basis Swaps IFERC/NYMEX(22) (22) —
(42) (42) —
Swing Swaps IFERC(3) (1) (2)(2) (1) (1)
Fixed Swaps/Futures(22) (22) —
(23) (23) —
Forward Physical Swaps(1) —
 (1)
Forward Physical Contracts(3) —
 (3)
Power:          
Forwards(9) —
 (9)(31) —
 (31)
Futures(1) (1) —
(8) (8) —
Natural Gas Liquids – Forwards/Swaps(261) (261) —
Refined Products — Futures(3) (3) —
Crude — Futures(1) (1) —
NGLs – Forwards/Swaps(409) (409) —
Refined Products – Futures(4) (4) —
Crude – Forwards/Swaps(1) (1) —
Total commodity derivatives(323) (311) (12)(523) (488) (35)
Total liabilities$(533) $(311) $(222)$(877) $(488) $(389)

   Fair Value Measurements at
December 31, 2018
 Fair Value Total Level 1 Level 2
Assets:     
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX$42
 $42
 $—
Swing Swaps IFERC52
 8
 44
Fixed Swaps/Futures97
 97
 —
Forward Physical Contracts20
 —
 20
Power:     
Forwards48
 —
 48
Futures1
 1
 —
Options – Calls1
 1
 —
NGLs – Forwards/Swaps291
 291
 —
Refined Products – Futures7
 7
 —
Crude – Forwards/Swaps1
 1
 —
Total commodity derivatives560
 448
 112
Other non-current assets26
 17
 9
Total assets$586
 $465
 $121
Liabilities:     
Interest rate derivatives$(163) $—
 $(163)
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX(91) (91) —
Swing Swaps IFERC(40) —
 (40)
Fixed Swaps/Futures(88) (88) —
Forward Physical Contracts(21) —
 (21)
Power:  

 

Forwards(42) —
 (42)
Futures(1) (1) —
NGLs – Forwards/Swaps(224) (224) —
Refined Products – Futures(15) (15) —
Crude – Forwards/Swaps(61) (61) —
Total commodity derivatives(583) (480) (103)
Total liabilities$(746) $(480) $(266)
   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)


6. NET INCOME PER LIMITED PARTNER UNIT
6.NET INCOME PER LIMITED PARTNER UNIT
A reconciliation of income and weighted average units used in computing basic and diluted income per unit is as follows:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Income from continuing operations$1,208
 $659
 $2,388
 $1,385
Less: Income from continuing operations attributable to noncontrolling interests317
 303
 614
 657
Less: Net income attributable to redeemable noncontrolling interests13
 —
 26
 —
Income from continuing operations, net of noncontrolling interests878
 356
 1,748
 728
Less: Series A Convertible Preferred Unitholders’ interest in income—
 12
 —
 33
Less: General Partner’s interest in income1
 1
 2
 2
Income from continuing operations available to Limited Partners$877
 $343
 $1,746
 $693
Basic Income from Continuing Operations per Limited Partner Unit:       
Weighted average limited partner units2,621.2
 1,114.8
 2,620.3
 1,097.1
Basic income from continuing operations per Limited Partner unit$0.33
 $0.31
 $0.67
 $0.63
Basic income (loss) from discontinued operations per Limited Partner unit$—
 $—
 $—
 $(0.01)
Diluted Income from Continuing Operations per Limited Partner Unit:       
Income from continuing operations available to Limited Partners$877
 $343
 $1,746
 $693
Dilutive effect of distributions to Series A Convertible Preferred Unitholders—
 12
 —
 33
Diluted income from continuing operations available to Limited Partners$877
 $355
 $1,746
 $726
Weighted average limited partner units2,621.2
 1,114.8
 2,620.3
 1,097.1
Dilutive effect of Series A Convertible Preferred Units—
 43.4
 —
 61.1
Dilutive effect of unvested unit awards9.8
 —
 9.8
 —
Weighted average limited partner units, assuming dilutive effect of unvested unit awards2,631.0
 1,158.2
 2,630.1
 1,158.2
Diluted income from continuing operations per Limited Partner unit$0.33
 $0.31
 $0.66
 $0.63
Diluted income (loss) from discontinued operations per Limited Partner unit$—
 $—
 $—
 $(0.01)
 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

7. DEBT OBLIGATIONS
7.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 bynotes was released in accordance with the terms of the applicable indentures governing such senior notes.

Subsidiary Indebtedness
ET-ETO Senior Notes Exchange
In February 2019, ETO commenced offers to exchange all of itsET’s outstanding senior notes for senior notes issued by ETO (the “ET-ETO senior notes exchange”).  Approximately 97% of ET’s outstanding senior notes were tendered and certainaccepted, and substantially all the exchanges settled on March 25, 2019. Following the exchange, the ET senior notes that were not tendered and remain outstanding as of its subsidiaries’ tangible and intangible assets.June 30, 2019 were as follows:
Energy Transfer Equity, L.P. Senior Notes Offering ���$52 million aggregate principal amount of 7.50% senior notes due 2020;
In October 2017, ETE issued $1 billion•$5 million aggregate principal amount of 4.25% senior notes due 2023. The $9902023;
•$23 million net proceeds fromaggregate principal amount of 5.875% senior notes due 2024; and
•$44 million aggregate principal amount of 5.50% senior notes due 2027.
In connection with the offering are intended to be used to repay a portionexchange, ETO issued approximately $4.21 billion aggregate principal amount of the outstanding indebtedness under ETE’s term loan facilityfollowing senior notes:
•$1.14 billion aggregate principal amount of 7.50% senior notes due 2020;
•$995 million aggregate principal amount of 4.25% senior notes due 2023;
•$1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and for general partnership purposes.

•$956 million aggregate principal amount of 5.50% senior notes due 2027.
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.
ETP 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 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility (described below) and for general partnership purposes.
The senior notes were registered under the Securities Act of 1933 (as amended). ETPETO 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. Interest on the senior notes is payable upon maturity and interest is paid semi-annually.
The senior notes are guaranteed by ETP on a senior unsecured basis 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’sETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETPETO may incur.  The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes.
ETLPETO Senior Notes Offering and Redemption
In January 2019, ETO issued the following senior notes:
•$750 million aggregate principal amount of 4.50% senior notes due 2024;
•$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and
•$1.75 billion aggregate principal amount of 6.25% senior notes due 2049.
The senior notes were registered under the Securities Act of 1933 (as amended).  ETO 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 on the senior notes is payable upon maturity and interest is paid semi-annually.
The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur.  The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes.
The $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the following:
•ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019;
•ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and
•Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019.

Panhandle Senior Notes Redemption
In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.
Bakken Senior Notes Offering
In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued the following senior notes related to the Bakken pipeline:
•$650 million aggregate principal amount of 3.625% senior notes due 2022;
•$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and
•$850 million aggregate principal amount of 4.625% senior notes due 2029.
The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.
Sunoco LP Senior Notes Offering
In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms.
USAC Senior Notes Offering
In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior unsecured notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes.
Credit Facilities and Commercial Paper
ETO 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, 2017,2019, the Sunoco LogisticsETO Five-Year Credit Facility had $35 million$2.37 billion of outstanding borrowings.borrowings, $2.36 billion of which was commercial paper. The amount available for future borrowings was $2.56 billion after taking into account letters of credit of $77 million. The weighted average interest rate on the total amount outstanding as of June 30, 2019 was 3.05%.
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 29, 2019. As of June 30, 2019, 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, 2017,2019, the Sunoco LP credit facilityCredit Facility had $644$117 million of outstanding borrowings and $9$8 million in standby letters of credit. As of June 30, 2019, Sunoco LP had $1.38 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, 20172019 was $847 million.4.41%.

USAC Credit Facility
On October 16, 2017, Sunoco LP entered intoUSAC 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, 2019, the Fifth AmendmentUSAC Credit Facility had $363 million of outstanding borrowings and no outstanding letters of credit. As of June 30, 2019, USAC had $1.24 billion of borrowing base availability and, subject to the Credit Agreementcompliance with the lenders party thereto and Bankapplicable financial covenants, available borrowing capacity of America, N.A., in its capacity$439 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding 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.June 30, 2019 was 5.10%.
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 billion credit facility provides substantially all of the remaining capital necessary to complete the projects. As of September 30, 2017, $2.50 billion was outstanding 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.
Compliance with Our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of SeptemberJune 30, 2017.2019.
8.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, 2019 included (i) $477 million related to the USAC Preferred Units described below and (ii) $23 million related to noncontrolling interest holders in one of ETO’s consolidated subsidiaries that have the option to sell their interests to ETO.
USAC Preferred Units
In January 2017, Energy Transfer Partners, L.P. repurchased all of its 1.9 million outstanding2018, USAC issued 500,000 USAC Preferred Units in a private placement at a price of $1,000 per USAC Preferred Unit, for cashtotal gross proceeds of $500 million.
The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in the aggregate amount of $53 million.certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed.
9.EQUITY
9. EQUITY
ETE
The changeschange in ETE common units and ConvertibleET Common Units during the ninesix months ended SeptemberJune 30,2017 were 2019 was as follows:
Six Months Ended June 30, 2019
Number of Common Units, beginning of period2,619.4
Common Units issued in connection with the distribution reinvestment plan3.4
Common Units issued under equity incentive plans and other0.4
Number of Common Units, end of period2,623.2

 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 wasAs of June 30, 2019, there have been no activitysales 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, ETE2019, ET did not repurchase any ETEET common units under its current buyback program. As of SeptemberJune 30, 2017,2019, $936 million remained available to repurchase under the current program.

ET Distribution Reinvestment Program
Subsidiary Equity Transactions
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, 2017,2019, distributions of $106$51 million were reinvested under the distribution reinvestment plan.
ETP August 2017 Units Offering
In August 2017, ETP issued 54program. As of June 30, 2019, a total of 37 million ETP common units remain available to be issued under the existing registration statement in an underwritten public offering. Netconnection with the distribution reinvestment program.
Subsidiary Equity Transactions
ETO Preferred Units
As of June 30, 2019 and December 31, 2018, ETO’s outstanding preferred units included 950,000 ETO Series A Preferred Units, 550,000ETOSeries B Preferred Units, 18,000,000 ETO Series C Preferred Units and 17,800,000 ETO Series D Preferred Units. As of June 30, 2019, ETO’s outstanding preferred units also included 32,000,000 ETO Series E Preferred Units.

ETO Series E Preferred Units Issuance
In April 2019, ETO issued 32 million of its 7.600% ETO Series E Preferred Units at a price of $25 per unit, including 4 million ETO Series E Preferred Units pursuant to the underwriters’ exercise of their option to purchase additional preferred units. The total gross proceeds of $997from the ETO Series E Preferred Unit issuance were $800 million, including $100 million from the offeringunderwriters’ exercise of their option. The net proceeds were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expendituresETO’s Five-Year Credit Facility and for general partnership purposes.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly ownsDistributions on the ETO Series E Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2024, at 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 eachrate 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.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all7.600% per annum of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns allstated liquidation preference of $25. On and after May 15, 2024, distributions on the ETO Series E Preferred Units will accumulate at a percentage of the economic interests$25 liquidation preference equal to an annual floating rate of PennTex,the three-month LIBOR, determined quarterly, plus a spread of 5.161% per annum. The ETO Series E Preferred Units are redeemable at ETO’s option on or after May 15, 2024 at a redemption price of $25 per ETO Series E 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, 2017,2019, Sunoco LP received net proceeds of $33 million from the issuance of 1.3 million Sunoco LP commonissued no 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, 2017,2019, $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 Class B Conversion
On MarchJuly 30, 2017,2019, the 6,397,965 USAC Class B units held by the Partnership purchased Sunoco LP’s 12.0 million series A preferredconverted into 6,397,965 common units representing limited partner interests in Sunoco LPUSAC. These common units will participate in a private placement transaction for an aggregate purchase priceany future distributions declared by USAC.
USAC Distribution Reinvestment Program
During the six months ended June 30, 2019, distributions of $300 million. The$0.5 million were reinvested under the USAC distribution ratereinvestment program resulting in the issuance 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 30,241 USAC common units.
Parent Company QuarterlyCash Distributions of Available
Distributions declared and/or paid subsequent to December 31, 2018 were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2018 February 8, 2019 February 19, 2019 $0.3050
March 31, 2019 May 7, 2019 May 20, 2019 0.3050
June 30, 2019 August 6, 2019 August 19, 2019 0.3050

ETO Cash Distributions
Following are distributionsDistributions declared and/or paid by usETO 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 (1)
 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.
Our distributions declared with respect to our Convertible Units subsequent to December 31, 20162018 were as follows:
Period Ended Record Date Payment Date 
Series A (1)
 
Series B (1)
 Series C Series D 
Series E (2)
December 31, 2018 February 1, 2019 February 15, 2019 $31.25
 $33.125
 $0.4609
 $0.4766
 $—
March 31, 2019 May 1, 2019 May 15, 2019 —
 —
 0.4609
 0.4766
 —
June 30, 2019 August 1, 2019 August 15, 2019 31.25
 33.125
 0.4609
 0.4766
 0.5806

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(1)    ETOSeries A Preferred Unit and ETO Series B Preferred Unit distributions are declared and paid in accordance with the ETP’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreement prioron a semi-annual basis.
(2)    ETO Series E Preferred Unit distributions related 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 inperiod ended June 30, 2019 represent 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 quarterlyprorated initial 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 subsequent to December 31, 2016:2018 were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2018 February 6, 2019 February 14, 2019 $0.8255
March 31, 2019 May 7, 2019 May 15, 2019 0.8255
June 30, 2019 August 6, 2019 August 14, 2019 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 subsequent to December 31, 2018 were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2018 January 28, 2019 February 8, 2019 $0.5250
March 31, 2019 April 29, 2019 May 10, 2019 0.5250
June 30, 2019 July 29, 2019 August 9, 2019 0.5250

Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
 June 30, 2019 December 31, 2018
Available-for-sale securities$10
 $2
Foreign currency translation adjustment(5) (5)
Actuarial loss related to pensions and other postretirement benefits(38) (48)
Investments in unconsolidated affiliates, net—
 9
Total AOCI, net of tax$(33) $(42)
 September 30, 2017 December 31, 2016
Available-for-sale securities$7
 $2
Foreign currency translation adjustment(5) (5)
Actuarial gain related to pensions and other postretirement benefits9
 7
Investments in unconsolidated affiliates, net3
 4
Subtotal14
 8
Amounts attributable to noncontrolling interest(14) (8)
Total AOCI, net of tax$—
 $—

10.INCOME TAXES
For the nine months ended September 30, 2017, theThe Partnership’s incomeeffective 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 resultingrate differs 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 taxstatutory rate was primarily due to higher nondeductible expenses amongpartnership earnings that are not subject to United States federal and most state income taxes at 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 amongpartnership level.
ETC Sunoco historically included certain government incentive payments as taxable income on its subsidiaries that resulted in a change in tax status for one of the subsidiaries. For the threefederal and nine months ended September 30, 2016, the Partnership’sstate 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
returns. In connection with ETC Sunoco’s 2004 through 2011 years, ETC Sunoco filed amended returns with the closingInternal Revenue Service (“IRS”) excluding these government incentive payments from federal taxable income. The IRS denied the amended returns and ETC Sunoco petitioned the Court of Federal Claims (“CFC”) on this issue. In November 2016, the CFC ruled against ETC Sunoco, and the Federal Circuit affirmed the CFC’s ruling on November 1, 2018. ETC Sunoco filed a petition for rehearing with the Federal Circuit on December 17, 2018, and this was denied on January 24, 2019. ETC Sunoco filed a petition for writ of certiorari with the United States Supreme Court that was docketed on May 24, 2019, to review the Federal Circuit’s affirmation of the contributionCFC’s ruling. The government filed its response to ETC Sunoco’s petition on July 24, 2019. The court will consider Sunoco’s petition at its Conference on October 1, 2019, and is likely to act on the petition within October 2019. If the court grants the petition, a decision would be expected by June 2020. The years before the court are 2004 through 2009, and 2010 through 2011 are on extension with the IRS. If ETC Sunoco is ultimately fully successful in this litigation, it will receive tax refunds of its propane operations in January 2012, ETLP (formerly Energy Transfer Partners, L.P.) agreedapproximately $530 million. However, due to provide contingent residual supportthe uncertainty surrounding the litigation, a reserve 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$530 million was previously established for the full amount of senior notes issued bythe pending refund claims. Due to the timing of the litigation and the related reserve, the receivable and reserve for this finance company subsidiary to third-party purchasers. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reductionissue have been netted in the amount supportedbalance sheets as of June 30, 2019 and December 31, 2018.
11.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
FERC Proceedings
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 ETLP underPanhandle are just and reasonable and set 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 supportmatter for any AmeriGas notes.

FERC Audithearing.  Panhandle filed a cost and revenue study on April 1, 2019.  An initial decision is expected to be issued in the first quarter of 2020.
In March 2016,By order issued February 19, 2019, the FERC commenced an auditinitiated a review of Trunkline for the period from January 1, 2013Southwest Gas Storage Company’s existing rates pursuant to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulationsSection 5 of the Uniform SystemNatural Gas Act to determine whether the rates currently charged by Southwest Gas Storage Company are just and reasonable and set the matter for hearing.  Southwest Gas Storage Company filed a cost and revenue study on May 6, 2019. On July 10, 2019, Southwest Gas Storage Company filed an Offer of Accounts as prescribedSettlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties.
In addition, on November 30, 2018, Sea Robin filed a rate case pursuant to Section 4 of the FERC,Natural Gas Act. On July 22, 2019, Sea Robin filed an Offer of Settlement in this Section 4 proceeding, which settlement was supported or not opposed by Commission Trial Staff and the FERC’s annual reporting requirements. The audit is ongoing.all active parties.
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 they fund their proportionate sharesshare of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their 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 statements of operations:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
ROW expense$6
 $7
 $12
 $13

PES Refinery Fire and Bankruptcy
We own an approximately 7.4% non-operating interest in PES, which owns a refinery in Philadelphia. In addition, Sunoco LP has historically purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex.
On July 21, 2019 (the "Petition Date"), 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 announced an intent to temporarily cease refinery operations.  The Debtors have also defaulted on a $75 million note payable to a subsidiary of the Partnership. The Partnership has not recorded a valuation allowance related to the note receivable as of June 30, 2019, because management is not yet able to determine the collectability of the note in bankruptcy.
In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of June 30, 2019, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such claims, 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; however, management is not currently able to estimate such additional liabilities.
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. The impact of the bankruptcy on the Partnership’s commercial contracts and related revenue loss (temporary or permanent) is unknown at this time, as the Debtors have expressed an intent to rebuild the refinery with the proceeds of insurance claims while concurrently running a sale process for its assets and operations.
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, 2016, the U.S.United States Army Corps of Engineers (“USACE”) issued permits to 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 of the Missouri River at Lake Oahe. After significant delay, theDakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also inRiver. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the U.S.United States District Court for the District of Columbia (“the Court”) against the USACE thatand challenged the legality of thethese permits issued for the construction of the 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.was pending, which the Court denied on September 9, 2016. 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 orderCheyenne River Sioux Tribe (“TRO”CRST”) 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. Thealso intervened. SRST filed an amended complaint and added claims based on treaties between the tribesSRST and CRST 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 presidentialPresidential 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 in the lawsuit in August 2016,CRST moved for a preliminary injunction and TROtemporary restraining order (“TRO”) to block operation of the pipeline. These motionspipeline, which motion was denied, and raised for the first time, claims based on the religious rights of the Tribe. The district court denied the TRO and preliminary injunction, 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.CRST.
TheIn June 2017, SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala Sioux and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into 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.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. 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 concluded 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 prior determinationdeterminations under certain of these statutes.
In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline.
On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent third party to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The assessment report was filed with the Court. Second, the Court directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access filed the revised plan with the Court. And third, the Court directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first and second reports were filed with the Court on December 29, 2017 and February 28, 2018, respectfully.
On February 8, 2018, the Court docketed a motion by CRST to “compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re remand process and remand conditions.” The motions sought an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access and the USACE opposed both motions. On April 16, 2018, the Court denied both motions.
On March 19, 2018, the Court denied YST’s motion for partial summary judgment and instead granted judgment in favor of Dakota Access pipeline and the USACE on the claims raised in YST’s motion. The Court ordered briefing to determine whetherconcluded that YST’s NHPA claims are moot because construction of the pipeline should remain in operation duringis complete and that the pendencygovernment’s review process did not violate NEPA or the various treaties cited by the YST.

On May 3, 2018, the Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. On June 8, 2018, the USACE filed a status report stating that they would conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they would need until August 31, 2018 to finish the remand process. On August 31, 2018, the USACE informed the Court that it had completed the remand process and that it had determined that the three issues remanded by the Court had been correctly decided. On October 1, 2018, the USACE produced a detailed remand analysis document supporting that determination. The Tribes and certain of the individuals sought leave of the Court to amend their complaints to challenge the remand process and the USACE’s reviewdecision on remand.
On January 3, 2019, the Court granted the Tribes’ requests to supplement their respective complaints challenging the remand process, or whethersubject to vacatedefendants’ right to argue later that such supplementation may be overbroad and not permitted by law. On January 10, 2019, the existing permits.Court denied the Oglala Sioux Tribe’s motion to amend its complaint to expand one of its pre-remand claims.
On January 17, 2019, the DOJ, on behalf of the USACE, moved to stay the litigation in light of the lapse in appropriations for the DOJ. The Tribes and individual plaintiffs opposed that request. On January 28, 2019, the USACE moved to withdraw this motion because appropriations for the DOJ had been restored. The Court granted this motion the next day.
On January 31, 2019, the USACE notified the Court that it had provided the administrative record for the remand to all parties. On February 27, 2019, the four Tribes filed a joint motion challenging the completeness of the record. The USACE opposed this motion in part, and Dakota Access opposed any shutdown of operations ofin full. The Tribes filed their reply brief on March 18, 2019 and the pipeline during this review process. motion is now fully briefed and before the Court.
On October 11, 2017,May 8, 2019, the Court issued an order allowingon Plaintiffs’ motion to complete the pipelineadministrative record, requiring the parties to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advisedsubmit additional information so that the Court can determine what documents, if any, should be added to the record. Following submittal of additional information by the parties, the Court issued an order on June 11, 2019 that it expectsdetermined which documents were to complete this additional work by April 2018.be added to the record. The Court has stayed consideration of any other claims until it fully resolves the remaining issues relatingset a briefing schedule for summary judgment motions. Plaintiffs’ motion for summary judgment is due by August 16, 2019 and defendants’ opposition and cross motions are due by October 9, 2019. Briefing is scheduled to its remand order.conclude by November 20, 2019.
While we believe that the pending lawsuits are unlikely to blockhalt or suspend 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.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’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. 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/orand Sunoco Inc. (R&M), along with other refiners, manufacturers and sellers of gasoline, (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, 2017,2019, Sunoco Inc. is a defendant in sixfive 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”), purportedPurported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger.Regency-ETO merger (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, 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”).
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.faith or fair to Regency. On March 29, 2016, the Delaware Court of Chancery granted defendants’Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Merger Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. A hearingOn February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP LP and Regency GP LLC (the “Regency Defendants”). On March 6, 2018, the Regency Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint. On April 26, 2019, the Court of Chancery granted Dieckman’s unopposed motion for class certification. On May 14, 2019, the Regency Defendants filed a motion for summary judgment arguing that Dieckman’s claims fail because the Regency Defendants relied on these motionsthe advice of their financial advisor in approving the Regency Merger. Also on May 14, 2019, Dieckman filed a motion for partial summary judgment arguing, among other things, that Regency’s conflicts committee was not properly formed. Trial is currently set for January 9, 2018.December 10-16, 2019.
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 ETPETO 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 ETPETO against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.ETO.  The jury also found that ETPETO owed Enterprise approximately $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETPETO and awarded ETPETO $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETPETO 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’sETO’s motion for rehearing to the Court of Appeals was denied. ETP intends to file aOn June 8, 2018, the Texas Supreme Court ordered briefing on the merits. On June 28, 2019, the Texas Supreme Court granted ETO’s 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 Courtset oral argument 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.

October 8, 2019.
Litigation Filed By or Against Williams
On April 6, 2016, Williams filed a complaint, The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG,(“Williams”) filed a complaint against ETEET and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the Issuanceissuance of the Partnership’s Series A Convertible Preferred Units (the “Issuance”) and (b) invalidate an amendment to ETE’sET’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On May 3, 2016, ETEET 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 AgreementET-Williams merger agreement (the “Merger Agreement”) by (a) blocking ETE’sET’s attempts to complete a public offering of the Series A Convertible Preferred 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 ETEET and LE GP and added 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-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged 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 representation and warranty 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 ETEET breached the Merger Agreement, (b) enjoin ETEET from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETEET from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETEET to close the merger or take various other affirmative actions.
ETEET filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETEET 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 ETEET 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. ETEET 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 ETEET on Williams’ claims in the Second Delaware WMBWilliams Litigation 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’sET’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 on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Defendants breached an additional representation 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,defenses. In response, 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.
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. Asas 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.

On December 1, 2017, the Court issued a Memorandum Opinion granting Williams’ motion to dismiss in part and denying Williams’ motion to dismiss in part. On April 16, 2018, the Court denied ET’s motion for re-argument of the Court decision granting Williams’ motion to dismiss in part. Discovery is ongoing, and a trial is expected in mid-2020.
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 Issuance
InOn April 12, 2016, two purported ETEET unitholders (the “Issuance Plaintiffs”“Plaintiffs”) filed putative class action lawsuits against ETE,ET, 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”“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 of the State of Delaware (the “Issuance Litigation”). Another purported ETEET unitholder, Chester County Employees’ Retirement Fund, later joined the consolidated action as an additional plaintiff of April 25, 2016.Issuance Litigation.
The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limitedET’s partnership agreement. The Issuance Plaintiffs seek,sought, among other things, preliminary and permanent injunctive relief that (a) prevents ETEET from making distributions to holders of the Series A Convertible Preferred Units and (b) invalidates an amendment to ETE’sET’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.
The matter was tried in front of Vice Chancellor Glasscock on February 19-21, 2018. Post-trial arguments were heard on April 16, 2018. In a post-trial opinion dated May 17, 2018, the Court found that one provision of the Issuance breached ET’s partnership agreement but that this breach caused no damages. The Court denied Plaintiffs’ requests for injunctive relief and declined to award damages or any other form of relief. Plaintiffs subsequently filed a motion seeking $8.5 million in attorneys’ fees and expenses from the Defendants, which the Defendants opposed. On May 6, 2019, the Court entered an Order and Final Judgment consistent with its May 2018 post-trial opinion.  The Court ordered that Energy Transfer pay $4.5 million in attorneys’ fees and expenses and also granted Plaintiffs’ Motion for Class Certification.
On June 5, 2019, Plaintiffs filed a notice of appeal from, among other things, the May 17, 2018 Memorandum Opinion 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 LitigationMay 6, 2019 Order and Final Judgment. Plaintiffs’ opening brief is currently set for February 19-21, 2018.due on or before July 22, 2019.

The Issuance Defendants cannot predict the outcome of the Issuance Litigationthis appeal or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation.this lawsuit. The Issuance Defendants believe that the Issuance Litigation isPlaintiffs’ claims are without merit and intend to defend vigorously against them.
Rover
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and Pretec Directional Drilling, LLC (“Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. Laney Directional Drilling Co., Atlas Trenchless, LLC, Mears Group, Inc., D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC, and B&T Directional Drilling, Inc. (collectively, with Rover and Pretec, “Defendants”) were added as defendants on April 17, 2018 and July 18, 2018.
Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover and other Defendants filed several motions to dismiss and Ohio EPA filed a motion in opposition. The State’s opposition to those motions was filed on October 12, 2018. Rover and other Defendants filed their replies on November 2, 2018. On March 13, 2019, the court granted Rover and the other Defendants’ motion to dismiss on all counts. On April 10, 2019, the Ohio EPA filed a notice of appeal. The Ohio EPA’s appeal is now pending before the Fifth District court of appeals and briefing is underway.
In January 2018, Ohio EPA sent a letter to the FERC to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24, 2018 response to the FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by the FERC and reviewed by the Ohio EPA. In addition, although the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs. Construction of Rover is now complete and the pipeline is fully operational.
Bayou 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 USACE’s issuance of 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. They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the USACE corrects alleged deficiencies in its decision-making process. ETO, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26, 2018. On March 27, 2018, Bayou Bridge filed an answer to the complaint.
On January 29, 2018, Plaintiffs filed motions for a preliminary injunction and TRO. United States District Court Judge Shelly Dick denied the TRO on January 30, 2018, but subsequently granted the preliminary injunction on February 23, 2018. On February 26, 2018, Bayou Bridge filed a notice of appeal and a motion to stay the February 23, 2018 preliminary injunction order. On February 27, 2018, Judge Dick issued an opinion that clarified her February 23, 2018 preliminary injunction order and denied Bayou Bridge’s February 26, 2018 motion to stay as moot. On March 1, 2018, Bayou Bridge filed a new notice of appeal and motion to stay the February 27, 2018 preliminary injunction order in the district court. On March 5, 2018, the district court denied the March 1, 2018 motion to stay the February 27, 2018 order.
On March 2, 2018, Bayou Bridge filed a motion to stay the preliminary injunction in the Fifth Circuit. On March 15, 2018, the Fifth Circuit granted a stay of injunction pending appeal and found that Bayou Bridge “is likely to succeed on the merits of its claim that the district court abused its discretion in granting a preliminary injunction.” Oral arguments were heard on the merits of the appeal, that is, whether the district court erred in granting the preliminary injunction in the Fifth Circuit on April 30, 2018. The district court has stayed the merits case pending decision of the Fifth Circuit. On May 10, 2018, the district court stayed the litigation pending a decision from the Fifth Circuit. On July 6, 2018, the Fifth Circuit vacated the Preliminary Injunction and remanded the case back to the district court. Construction is ongoing.
On August 14, 2018, Plaintiffs sought leave of court to amend their complaint to add an “as applied” challenge to the USACE’s application of the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 18, 2018. On September 18, 2018, Plaintiffs filed a motion for partial summary judgment on the issue of the

USACE’s analysis of the risks of an oil spill once the pipeline is in operation. On November 6, 2018, the court struck plaintiffs’ motion as premature.
At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiffs’ original complaint, which it has done. Challenges to the completeness of the record have been briefed and any other actionsare currently pending before the court. At the October 18, 2018 conference, the court also scheduled summary judgment briefing on Plaintiffs’ original complaint; briefing is scheduled to conclude by the end of 2019.
On December 28, 2018, Judge Dick issued a General Order for the Middle District of Louisiana holding in abeyance all civil matters where the United States is a party. Notwithstanding the General Order, on January 11, 2019, Plaintiffs filed a Motion for Summary Judgment on their National Environmental Policy Act and Clean Waters Act claims.
On January 11, 2019, Plaintiffs attempted to file a Motion for Summary Judgment on its National Environmental Policy Act and Coastal Water Authority claims. On January 23, 2019, Plaintiffs filed a Second Motion for Preliminary Injunction based on alleged permit violations, which the court later denied. On February 11, 2019, the court denied Plaintiffs’ August 14, 2018 motion for leave to amend their complaint.
On February 14, 2019, Judge Dick ordered that all summary judgment briefing is stayed until the court rules on the motions challenging the Issuance.completeness of the administrative record. Judge Dick further ordered that once those motions are decided, the parties will be allowed to update any summary judgment briefs they have already filed, if necessary, and that the court will set new briefing deadlines.
Litigation filed by BP Products
On April 30, 2015, BP Products North America Inc. (“BP”)26, 2019, Plaintiffs filed a complaintmotion seeking reconsideration of Judge Dick’s February 14, 2019 order staying summary judgment briefing. Defendants filed their oppositions on May 6, 2019.
On May 14, 2019, Judge Dick issued orders denying the outstanding record motions and Plaintiffs’ motion seeking reconsideration of the February 14, 2019 order.
On May 22, 2019, in a telephonic status conference, Judge Dick set a schedule for summary judgment briefing. Plaintiffs filed their motion for summary judgment on July 8, 2019 and defendants’ oppositions and cross-motions are due on August 9, 2019. Briefing is set to conclude by September 20, 2019.
Revolution
On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line, in the vicinity of Ivy Lane located in Center Township, Beaver County, Pennsylvania. There were no injuries, but there were evacuations of local residents as a precautionary measure. The Pennsylvania Department of Environmental Protection (“PADEP”) and the Pennsylvania Public Utility Commission (“PUC”) are investigating the incident. On October 29, 2018, PADEP issued a Compliance Order requiring our subsidiary, ETC Northeast Pipeline, LLC (“ETC Northeast”), to cease all earth disturbance activities at the site (except as necessary to repair and maintain existing Best Management Practices (“BMPs”) and temporarily stabilize disturbed areas), implement and/or maintain the Erosion and Sediment BMPs at the site, stake the limit of disturbance, identify and report all areas of non-compliance, and submit an updated Erosion and Sediment Control Plan, a Temporary Stabilization Plan, and an updated Post Construction Stormwater Management Plan. The scope of the Compliance Order has been expanded to include the disclosure to PADEP of alleged violations of environmental permits with respect to various construction and post-construction activities and restoration obligations along the 42-mile route of the Revolution line. ETC Northeast filed an appeal of the Compliance Order 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”),Pennsylvania Environmental Hearing Board.
On February 8, 2019, PADEP filed a wholly-owned subsidiaryPetition to Enforce the Compliance Order with Pennsylvania’s Commonwealth Court. The court issued an Order on February 14, 2019 requiring the submission 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 historyanswer to the level that existed prior to the execution of the agreements with the other shippers,Petition on or before March 12, 2019, and (4) order damages to BP of approximately $62 million,scheduled 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 heldPetition for March 26, 2019.  On March 12, 2019, ETC Northeast answered the Petition.  ETC Northeast and PADEP have since agreed to a Stipulated Order regarding the issues raised in November 2016.
the Compliance Order, which obviated the need for a hearing. The Commonwealth Court approved the Stipulated Order on March 26, 2019.  On February 8, 2019, PADEP also issued a Permit Hold on any requests for approvals/permits or permit amendments made by us or any of our subsidiaries for any projects in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board on March 11, 2019. On May 26, 2017,14, 2019, PADEP issued a Compliance Order related to impacts to streams and wetlands. The Partnership filed an appeal of the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued her initial decision (“Initial Decision”)Streams and found that SPLP had acted discriminatorily by entering into T&D agreementsWetlands Compliance Order on June 14, 2019. The Partnership continues to work through these issues with PADEP.
The Pennsylvania Office of Attorney General has commenced an investigation regarding the two shippers other than BP and recommended thatIncident. The scope of this investigation is currently unknown.

Chester County, Pennsylvania Investigation
In December 2018, 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 historyChester County District Attorney sent a letter 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, butPartnership stating that it was not entitled to damages more than two years priorinvestigating the Partnership and related entities for “potential crimes” related to the filingMariner East pipelines.
Between April and May 2019, the Partnership was served with a total of twenty-three grand jury subpoenas seeking a variety of documents and records sought by the Chester County Investigation Grand Jury. While the Partnership will cooperate with the investigation, it intends to vigorously defend itself against these allegations.
Delaware County, Pennsylvania Investigation
On March 11, 2019, the Delaware County District Attorney’s Office (“Delaware County D.A.”) announced that the Delaware County D.A. and the Pennsylvania Attorney General’s Office, at the request of the complaint.
On July 26, 2017, eachDelaware County D.A., are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the parties filedMariner East pipelines in Delaware County. The Partnership has not been appraised of the specific conduct under investigation. This investigation is ongoing. While the Partnership will cooperate with the FERC a brief on exceptionsinvestigation, it intends 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.

vigorously defend itself against these allegations.
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, 20172019 and December 31, 2016,2018, accruals of approximately $68$54 million and $77$55 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 ViolationsOn April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“NOVs”Complaint”) fromagainst SPLP before the Delaware County Regional Water Quality Control AuthorityPUC. Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“DELCORA”ME1,” “ME2” or “ME2x”) in connectionWest Whiteland Township (“the Township”) are unreasonable, unsafe, inadequate, and insufficient for, among other reasons, selecting an improper and unsafe route through densely populated portions of the Township with a discharge at its Marcus Hook Industrial Complex (“MHIC”) in July 2016. Sunoco Logistics also entered in a Consent Orderhomes, schools, 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,infrastructure and ETP is currently in discussions with the PADEPcausing inadvertent returns 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 occurredsinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public 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 watersdangers of the State, storm water control violations, improper disposalpipeline; (iii) the construction of spent drilling mud containing diesel fuel residuals,ME2 and open burning. The alleged violations occurred from AprilME2x increases the risk of damage to July, 2017. The Ohio EPA has proposed penaltiesthe existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’s Complaint seeks emergency relief by way of approximately $2.3 millionan order (i) prohibiting construction of ME2 and ME2x in connection with the alleged violationsTownship; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and is seeking certain corrective actions. ETP is working with Ohio EPA(ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until SPLP fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in which they sit; (iv) requiring SPLP to resolverelease to the matter. The timing or outcomepublic its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of this matter cannot be reasonably determined at this time; however, we do not expect there to beoperation of ME1 and suspend further construction of ME2 and ME2x in the Township.
Following a material impact to our results of operations, cash flows or financial position.
In addition,hearing on May 7 and 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment 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 Protection2018, Administrative Law Judge Elizabeth H. Barnes (“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”ALJ”) issued an order toOrder on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to cease HDD activitiesshut down ME1, to discontinue construction of ME2 and ME2x within the Township, and required SPLP to provide various types of information and perform various geotechnical and geophysical studies within the Township. The ALJ’s Order was immediately effective, and SPLP complied by shutting down service on ME1 and discontinuing all construction in Pennsylvania relatedthe Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the Mariner EastPUC, which issued an Opinion and Order on June 15, 2018 (following a public meeting on June 14, 2018) that reversed in part and affirmed in part the ALJ’s Order. PUC’s Opinion and Order permitted SPLP to resume service on ME1, but continued the shutdown of construction on ME2 and ME2x pending the submission of the following three types of information to PUC: (i) inspection and testing protocols; (ii) comprehensive emergency response plan; and (iii) safety training curriculum for employees and contractors. SPLP submitted the required information on June 22, 2018. On July 2, project.2018, Senator Dinniman and intervenors responded to the submission.

SPLP is also required to provide an affidavit that the PADEP has issued appropriate approvals for construction of ME2 and ME2x in the Township before recommencing construction of ME2 and ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 1, 20172, 2018, the EHB liftedPUC entered an Order lifting the order as to two drill locations.  On August 3, 2017,stay of construction on ME2 and ME2x in the EHB lifted the order as 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 settlementTownship with respect to four of the eight areas within the Township where the necessary environmental permits had been issued. Subsequently, after PADEP’s issuance of permit modifications for two of the four remaining HDD locationsconstruction sites, the PUC lifted the construction stay on those two sites as well. Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue this matter. Sunoco submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and facilitated a settlement meeting.  On August 7, 2017 a final settlement was reached.  A stipulated orderintervenors opposed that petition.
Briefing in the Commonwealth Court has been submittedcompleted. On June 3, 2019, the Commonwealth Court heard argument on whether Senator Dinniman has standing. If the court finds that he does not, the case would likely be remanded to the EHB Judge with respect toPUC, 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 partiesstay will be lifted and the reevaluationinjunction may be dissolved because the Complainant did not have standing to bring the case in the first instance.
On March 29, 2019, SPLP filed a supplemental affidavit with the PUC in accordance with the established procedure to request the PUC lift the stay 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 returnsconstruction 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 planME2 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.remaining work locations in the Township – Shoen Road. That same day, Senator Dinniman filed a letter objecting to SPLP’s request, arguing the Commonwealth Court’s order staying all proceedings barred the PUC from issuing an approval to lift the stay of construction of ME2 at Shoen Road. SPLP filed a reply to Senator Dinniman’s letter on April 4, 2019 explaining that the Commonwealth Court’s order did not prevent the PUC from lifting the stay of construction of ME2 at Shoen Road. On April 25, 2019, the PUC issued an Opinion and Order that it lacked jurisdiction to lift the stay of construction of ME2 at Shoen Road in light of the Commonwealth Court’s order staying proceedings in the PUC. That same day, SPLP filed an Application for Expedited Clarification to the Commonwealth Court, which sought to clarify that the Commonwealth Court’s stay of proceedings does not prevent the PUC from issuing an approval to lift the stay of construction of ME2 at Shoen Road, or any of the other remaining work locations in the Township. Senator Dinniman’s response to SPLP’s application was filed on May 8, 2019, and oral argument was held on May 15, 2019. On May 20, 2019, the Commonwealth Court upheld the PUC Opinion that the PUC approval of work at Shoen Road remains stayed until the Commonwealth Court rules on the standing of Senator Dinniman.
No amounts have been recorded in our SeptemberJune 30, 20172019 or December 31, 20162018 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
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 the 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 May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental QualityJanuary 2019, a summary of the emergency response and remedial efforts takenConsent Decree approved by SPLP after the releases occurredall parties as well as operational changes institutedan 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 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.
On January 3, 2018, PADEP issued an Administrative Order to SPLP directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February 2017, during the construction of the project.  SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so SPLP took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, SPLP entered into a Consent Order and Agreement with PADEP that (i) withdraws the Administrative Order; (ii) establishes requirements for compliance with permits on a going forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to reducepay a $12.6 million civil penalty to the likelihoodCommonwealth of future releases.Pennsylvania.  In July, wethe Consent Order and agreement, SPLP admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that SPLP had a follow-up meetingadequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the DOJ, EPApermits. SPLP concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
In October 2018, Pipeline Hazardous Materials Safety Administration (“PHMSA”) issued a notice of proposed safety order (the “Notice”) to SPMT, a wholly owned subsidiary of ET. The Notice alleged that conditions exist on certain pipeline facilities owned and Louisiana Departmentoperated 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 Environmental Quality during whichfact and proposed corrective measures. SPMT responded to the agencies presented their initial demand for civil penaltiesNotice by submitting a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and injunctive relief. In short,entered into a consent agreement with PHMSA resolving the DOJ and EPA proposed federal penalties totaling $7 million forissues in the three releases along withNotice 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 demand for injunctive relief, and Louisiana Department of Environmental Quality proposedcomplaint against SPLP seeking a state penalty of approximatelyup to $1 million related to resolvea May 2018 rupture near Edmond, Oklahoma.  The rupture occurred on the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joinedNoble to Douglas 8” pipeline in an area of external corrosion and caused the penalty discussions at this point. We are currently working on a counterofferrelease of approximately fifteen barrels of crude oil. SPLP responded immediately to the Louisiana Department of Environmental Quality.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.
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 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.
•
legacy sites related to ETC Sunoco that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that ETC Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.
•
ETC 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, 2019, ETC Sunoco had been named as a PRP at approximately 38 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. ETC Sunoco is usually one of a number of companies identified as a PRP at a site. ETC Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon ETC 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, 2019 December 31, 2018
Current$46
 $42
Non-current278
 295
Total environmental liabilities$324
 $337

 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, 20172019 and 2016,2018, the Partnership recorded $7$9 million and $12$9 million, respectively, of expenditures related to environmental cleanup programs. During the ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, 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 the PHMSA, pursuant to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated withwhich 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, EPAPHMSA 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, the refinery. Specifically, EPAPHMSA, through the Office 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.
12.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 16 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.

12. DERIVATIVE ASSETS AND LIABILITIESThe 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 allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as prepayments or 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, 2018$392
Additions300
Revenue recognized(315)
Balance, June 30, 2019$377
  
Balance, January 1, 2018$215
Additions216
Revenue recognized(143)
Balance, June 30, 2018$288
The balances of receivables from contracts with customers listed in the table below, all of which are attributable to Sunoco LP, include both current trade receivables and long-term receivables, net of allowance for doubtful accounts. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis.
The balances of Sunoco LP’s contract assets as of June 30, 2019 and December 31, 2018 were as follows:
 June 30, 2019 December 31, 2018
Contract balances:   
Contract asset$95
 $75
Accounts receivable from contracts with customers533
 348

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 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, 2019 and 2018 was $4 million and $3 million, respectively. The amount of amortization expense that Sunoco LP recognized for the six months ended June 30, 2019 and 2018 was $8 million and $6 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.
Performance Obligations
At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total expected contract consideration to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when

the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contacts, only the fixed component of the contracts are included in the table below.
As of June 30, 2019, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $40.79 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:
  Years Ending December 31,    
  2019 (remainder) 2020 2021 Thereafter Total
Revenue expected to be recognized on contracts with customers existing as of June 30, 2019 $3,427
 $5,091
 $4,545
 $27,729
 $40,792

13.LEASE ACCOUNTING
Lessee Accounting
The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet.
At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.
Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership, and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.
To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives.
Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance.
For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.

The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of June 30, 2019 were as follows:
 June 30, 2019
Operating leases: 
Lease right-of-use assets, net$849
Operating lease current liabilities59
Accrued and other current liabilities1
Non-current operating lease liabilities803
Finance leases: 
Property, plant and equipment, net$2
Lease right-of-use assets, net4
Accrued and other current liabilities1
Long-term debt, less current maturities7
Other non-current liabilities2

The components of lease expense for the three and six months ended June 30, 2019 were as follows:
  Income Statement Location Three Months Ended June 30, 2019 Six Months Ended June 30, 2019
Operating lease costs:    
Operating lease cost Cost of goods sold $8
 $16
Operating lease cost Operating expenses 19
 36
Operating lease cost Selling, general and administrative 4
 7
Total operating lease costs 31
 59
Finance lease costs:    
Amortization of lease assets Depreciation, depletion and amortization 1
 2
Interest on lease liabilities Interest expense, net of capitalized interest —
 —
Total finance lease costs 1
 2
Short-term lease cost Operating expenses 12
 23
Variable lease cost Operating expenses 5
 8
Lease costs, gross 49
 92
Less: Sublease income Other revenue 12
 23
Lease costs, net $37
 $69

The weighted average remaining lease terms and weighted average discount rates as of June 30, 2019 were as follows:
June 30, 2019
Weighted-average remaining lease term (years):
Operating leases22
Finance leases10
Weighted-average discount rate (%):
Operating leases5%
Finance leases8%


Cash flows and non-cash activity related to leases for the six months ended June 30, 2019 were as follows:
 Six Months Ended June 30, 2019
Operating cash flows from operating leases$(79)
Lease assets obtained in exchange for new lease liabilities15

Maturities of lease liabilities as of June 30, 2019 are as follows:
 Operating Leases Finance Leases Total
2019 (remainder)$55
 $1
 $56
202093
 2
 95
202184
 2
 86
202271
 1
 72
202367
 1
 68
Thereafter1,152
 6
 1,158
Total lease payments1,522
 13
 1,535
Less: present value discount659
 3
 662
Present value of lease liabilities$863
 $10
 $873

Lessor Accounting
Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.
Rental income included in other revenue in our consolidated statement of operations for the three and six months ended June 30, 2019 was $36 million and $72 million, respectively.
Future minimum operating lease payments receivable as of June 30, 2019 are as follows:
 Lease Receivables
2019 (remainder)$46
202072
202159
202253
20234
Thereafter5
Total undiscounted cash flows$239

14.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, 2019 December 31, 2018
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)
13,038
 2019-2020 16,845
 2019-2020
Fixed Swaps/Futures1,297,500
 2017-2018 (682,500) 2017775
 2019-2020 468
 2019
Basis Swaps IFERC/NYMEX (1)
(15,810,000) 2017-2019 2,242,500
 2017
Options – Puts13,000,000
 2018 —
 ——
 — 10,000
 2019
Power (Megawatt):        
Forwards665,040
 2017-2018 391,880
 2017-20182,554,800
 2019-2029 3,141,520
 2019
Futures(213,840) 2017-2018 109,564
 2017-20181,095,558
 2019-2021 56,656
 2019-2021
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 – Puts175,200
 2019 18,400
 2019
Options – Calls317,600
 2019-2020 284,800
 2019
(Non-Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Basis Swaps IFERC/NYMEX67,500
 2017-2020 10,750,000
 2017-2018(23,115) 2019-2022 (30,228) 2019-2021
Swing Swaps IFERC91,897,500
 2017-2019 (5,662,500) 20178,480
 2019-2020 54,158
 2019-2020
Fixed Swaps/Futures(20,220,000) 2017-2019 (52,652,500) 2017-2019(3,505) 2019-2021 (1,068) 2019-2021
Forward Physical Contracts(140,937,993) 2017-2018 (22,492,489) 2017(22,542) 2019-2021 (123,254) 2019-2020
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(1,612) 2019-2021 (2,135) 2019
Refined Products (MBbls) – Futures(126) 2019-2021 (1,403) 2019
Crude (MBbls) – Forwards/Swaps18,670
 2019-2020 20,888
 2019
Corn (thousand bushels)(2,605) 2019 (1,920) 2019
Fair Value Hedging Derivatives        
(Non-Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Basis Swaps IFERC/NYMEX(41,102,500) 2017 (36,370,000) 2017(31,703) 2019-2020 (17,445) 2019
Fixed Swaps/Futures(41,102,500) 2017 (36,370,000) 2017(31,703) 2019-2020 (17,445) 2019
Hedged Item — Inventory41,102,500
 2017 36,370,000
 2017
Hedged Item – Inventory31,703
 2019-2020 17,445
 2019
(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 
Type(1)
 Notional Amount Outstanding
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
Term 
Type(1)
 June 30, 2019 December 31, 2018
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
$—
 $400
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 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
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
 —
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
 Pay a floating rate and receive a fixed rate of 1.42% —
 300
(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.
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, 2019 December 31, 2018 June 30, 2019 December 31, 2018
Derivatives designated as hedging instruments:        
Commodity derivatives (margin deposits) $14
 $—
 $—
 $(13)
Derivatives not designated as hedging instruments:        
Commodity derivatives (margin deposits) 406
 402
 (438) (397)
Commodity derivatives 121
 158
 (85) (173)
Interest rate derivatives —
 —
 (354) (163)
  527
 560
 (877) (733)
Total derivatives $541
 $560
 $(877) $(746)
 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, 2019 December 31, 2018 June 30, 2019 December 31, 2018
Derivatives without offsetting agreements Derivative assets (liabilities) $—
 $—
 $(210) $(194) Derivative liabilities $—
 $—
 $(354) $(163)
Derivatives in offsetting agreements:Derivatives in offsetting agreements:        Derivatives in offsetting agreements:        
OTC contracts Derivative assets (liabilities) 52
 25
 (61) (58) Derivative assets (liabilities) 121
 158
 (85) (173)
Broker cleared derivative contracts Other current assets 229
 338
 (262) (420) Other current assets (liabilities) 420
 402
 (438) (410)
Total gross derivativesTotal gross derivatives 281
 363
 (533) (672)Total gross derivatives 541
 560
 (877) (746)
Less offsetting agreements:        
Offsetting agreements:Offsetting agreements:        
Counterparty netting Derivative assets (liabilities) (10) (4) 10
 4
 Derivative assets (liabilities) (67) (47) 67
 47
Payments on margin deposit Other current assets (220) (338) 220
 338
Counterparty netting Other current assets (liabilities) (406) (397) 406
 397
Total net derivativesTotal net derivatives $51
 $21
 $(303) $(330)Total net derivatives $68
 $116
 $(404) $(302)
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 summarize the amounts recognized in income with respect to our derivative financial instruments:
 Location of Gain Recognized in Income on Derivatives Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
   Three Months Ended
June 30,		 Six Months Ended
June 30,
   2019 2018 2019 2018
Derivatives in fair value hedging relationships (including hedged item):         
Commodity derivativesCost of products sold $—
 $6
 $—
 $9

  
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
 Location of Gain (Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives
   Three Months Ended
June 30,		 Six Months Ended
June 30,
   2019 2018 2019 2018
Derivatives not designated as hedging instruments:         
Commodity derivatives – TradingCost of products sold $(20) $16
 $(14) $33
Commodity derivatives – Non-tradingCost of products sold (29) (295) (41) (366)
Interest rate derivativesGains (losses) on interest rate derivatives (122) 20
 (196) 72
Total  $(171) $(259) $(251) $(261)

15.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,
 2019 2018 2019 2018
Revenues from related companies$136
 $120
 $245
 $222
The following table summarizes the accounts receivable from related companies on our consolidated balance sheets:
13. RELATED PARTY TRANSACTIONS
 June 30, 2019 December 31, 2018
Accounts receivable from related companies:   
FGT$32
 $25
Phillips 6647
 42
Other32
 44
Total accounts receivable from related companies$111
 $111

InAs of June 2017, ETP acquired all of30, 2019 and December 31, 2018, 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 $14 million and $49$59 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
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

16.REPORTABLE SEGMENTS
the goodwill and property, plant and equipment fair value adjustments recorded asAs a result of the 2004 reverse acquisitionEnergy Transfer Merger in October 2018, our reportable segments were reevaluated and currently reflect the following segments, which conduct their business primarily in the United States:
•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
•all other.
Consolidated revenues and expenses reflect the elimination of Heritage Propane Partners, L.P.all material intercompany transactions.
The Investmentinvestment in Sunoco LPUSAC segment reflects the results of USAC beginning April 2018, the date that the Partnership obtained control of USAC.
Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, 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 are primarily reflected in refined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and the legacy Sunoco, Inc. retail business for the periods presented.other fees. Revenues from our all other segment are primarily reflected in natural gas sales.
We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment 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 value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’sour proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations.ownership.

The following tables present financial information by segment:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Revenues:       
Intrastate transportation and storage:       
Revenues from external customers$671
 $761
 $1,440
 $1,578
Intersegment revenues94
 52
 181
 110
 765
 813
 1,621
 1,688
Interstate transportation and storage:       
Revenues from external customers487
 373
 979
 735
Intersegment revenues6
 5
 12
 8
 493
 378
 991
 743
Midstream:       
Revenues from external customers337
 594
 1,000
 1,034
Intersegment revenues861
 1,280
 1,916
 2,454
 1,198
 1,874
 2,916
 3,488
NGL and refined products transportation and services:       
Revenues from external customers2,356
 2,359
 5,069
 4,622
Intersegment revenues256
 209
 574
 492
 2,612
 2,568
 5,643
 5,114
Crude oil transportation and services:       
Revenues from external customers5,012
 4,789
 9,179
 8,520
Intersegment revenues34
 14
 53
 28
 5,046
 4,803
 9,232
 8,548
Investment in Sunoco LP:       
Revenues from external customers4,474
 4,606
 8,166
 8,354
Intersegment revenues1
 1
 1
 2
 4,475
 4,607
 8,167
 8,356
Investment in USAC:       
Revenues from external customers169
 165
 336
 165
Intersegment revenues5
 2
 9
 2
 174
 167
 345
 167
All other:       
Revenues from external customers371
 471
 829
 992
Intersegment revenues20
 31
 59
 81
 391
 502
 888
 1,073
Eliminations(1,277) (1,594) (2,805) (3,177)
Total revenues$13,877
 $14,118
 $26,998
 $26,000
 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,
 2019 2018 2019 2018
Segment Adjusted EBITDA:       
Intrastate transportation and storage$290
 $208
 $542
 $400
Interstate transportation and storage460
 375
 916
 741
Midstream412
 414
 794
 791
NGL and refined products transportation and services644
 461
 1,256
 912
Crude oil transportation and services751
 548
 1,557
 1,012
Investment in Sunoco LP152
 140
 305
 249
Investment in USAC105
 95
 206
 95
All other10
 21
 45
 64
Total2,824
 2,262
 5,621
 4,264
Depreciation, depletion and amortization(785) (694) (1,559) (1,359)
Interest expense, net of interest capitalized(578) (510) (1,168) (976)
Impairment losses—
 —
 (50) —
Gains (losses) on interest rate derivatives(122) 20
 (196) 72
Non-cash compensation expense(29) (32) (58) (55)
Unrealized gains (losses) on commodity risk management activities(23) (265) 26
 (352)
Losses on extinguishments of debt—
 —
 (18) (106)
Inventory valuation adjustments4
 32
 97
 57
Adjusted EBITDA related to unconsolidated affiliates(163) (168) (309) (324)
Equity in earnings of unconsolidated affiliates77
 92
 142
 171
Adjusted EBITDA related to discontinued operations—
 5
 —
 25
Other, net37
 (15) 20
 26
Income from continuing operations before income tax expense1,242
 727
 2,548
 1,443
Income tax expense from continuing operations(34) (68) (160) (58)
Income from continuing operations1,208
 659
 2,388
 1,385
Loss from discontinued operations, net of income taxes—
 (26) —
 (263)
Net income$1,208
 $633
 $2,388
 $1,122
 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

 June 30, 2019 December 31, 2018
Assets:   
Intrastate transportation and storage$6,159
 $6,365
Interstate transportation and storage15,606
 15,081
Midstream19,866
 19,745
NGL and refined products transportation and services19,409
 18,267
Crude oil transportation and services18,790
 18,022
Investment in Sunoco LP5,470
 4,879
Investment in USAC3,760
 3,775
All other and eliminations1,752
 2,112
Total assets$90,812
 $88,246
 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
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.


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
17.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)

 June 30, 2019 December 31, 2018
ASSETS   
Current assets:   
Cash and cash equivalents$1
 $2
Accounts receivable from related companies—
 65
Other current assets—
 1
Total current assets1
 68
Property, plant and equipment, net23
 23
Advances to and investments in unconsolidated affiliates25,411
 26,581
Total assets$25,435
 $26,672
LIABILITIES AND PARTNERS’ CAPITAL   
Current liabilities:   
Accounts payable$—
 $2
Accounts payable to related companies58
 65
Interest payable1
 76
Accrued and other current liabilities1
 3
Total current liabilities60
 146
Long-term debt, less current maturities124
 5,519
Long-term notes payable – related companies4,416
 445
Other non-current liabilities1
 3
Commitments and contingencies   
Partners’ capital   
Limited Partners:   
Common Unitholders20,872
 20,606
General Partner(5) (5)
Accumulated other comprehensive loss(33) (42)
Total partners’ capital20,834
 20,559
Total liabilities and partners’ capital$25,435
 $26,672
 September 30, 2017 December 31, 2016
ASSETS   
Current assets:   
Cash and cash equivalents$—
 $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
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
SELLING, GENERAL AND ADMINISTRATIVE EXPENSE$(5) $(9) $(6) $(11)
OTHER INCOME (EXPENSE):       
Interest expense, net—
 (90) (63) (176)
Interest expense, net – related company(67) —
 (88) —
Equity in earnings of unconsolidated affiliates949
 454
 1,917
 902
Losses on extinguishments of debt—
 —
 (16) —
Other, net—
 —
 3
 3
INCOME BEFORE INCOME TAXES877
 355
 1,747
 718
Income tax benefit(1) —
 (1) —
NET INCOME878
 355
 1,748
 718
Series A Convertible Preferred Unitholders’ interest in income—
 12
 —
 33
General Partner’s interest in net income1
 1
 2
 2
Limited Partners’ interest in net income$877
 $342
 $1,746
 $683

 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)
 Six Months Ended
June 30,
 2019 2018
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES$2,948
 $626
INVESTING ACTIVITIES   
Contributions to unconsolidated affiliate—
 (250)
Sunoco LP Series A Preferred Units redemption—
 303
Net cash provided by investing activities—
 53
FINANCING ACTIVITIES   
Proceeds from borrowings—
 355
Principal payments on debt(1,220) (587)
Proceeds from (payments to) affiliate(180) 85
Distributions to partners(1,549) (532)
Net cash used in financing activities(2,949) (679)
CHANGE IN CASH AND CASH EQUIVALENTS(1) —
CASH AND CASH EQUIVALENTS, beginning of period2
 1
CASH AND CASH EQUIVALENTS, end of period$1
 $1
 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, 2018 filed with the SEC on October 2, 2017.February 22, 2019. 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, 2016.2018 filed with the SEC on February 22, 2019.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE”“ET” mean Energy Transfer LP (formerly Energy Transfer Equity, L.P.) 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, ourET directly and indirectly owns equity interests in ETP andETO, Sunoco LP consistedand USAC, all of 100%which are limited partnerships engaged in diversified energy-related services. Sunoco LP and USAC have publicly traded common units.
The Parent Company’s principal sources of cash flow is derived from its investment in ETO. ETO’s earnings and cash flows are generated by its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The amount of cash that ETO, Sunoco LP and USAC 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 order to fully understand the financial condition and results of operations of the respective general partner interestsParent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.
General
Our primary objective is to increase the level of our distributable cash flow to our unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and IDRs, as well as 27.5 million ETP common units, 2.3 million Sunoco LP common unitsliquids businesses through, among other things, pursuing certain construction and 12 million Sunoco LP Series A Preferred Units held by usexpansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our wholly-owned subsidiaries.subsidiaries generate from their operations.
Our reportable segments are as follows:
Investment in ETP, including the consolidated operations of ETP;intrastate transportation and storage;
Investmentinterstate transportation and storage;
midstream;
NGL and refined products transportation and services;
crude oil transportation and services;
investment in Sunoco LP, including the consolidated operationsLP;
investment in USAC; and
all other.
The general partner of Sunoco LP;ETO has separate operating management and board of directors. We control ETO through our ownership of its general partner.
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
ETEJ.C. Nolan
On July 1, 2019, ETO entered into a joint venture with Sunoco LP, under which ETO will operate a pipeline that will transport diesel fuel from Hebert, Texas to a terminal near Midland, Texas on behalf of the joint venture. The diesel fuel pipeline will have an initial capacity of 30,000 barrels per day and was successfully commissioned in August 2019.
ETO Series E Preferred Units Issuance
In April 2019, ETO issued 32 million of its 7.600% ETO Series E Preferred Units at a price of $25 per unit, including 4 million ETO Series E Preferred Units pursuant to the underwriters’ exercise of their option to purchase additional preferred units. The total gross proceeds from the ETO Series E Preferred Unit issuance were $800 million, including $100 million from the underwriters’ exercise of their option. The net proceeds were used to repay amounts outstanding under ETO’s Five-Year Credit Facility and for general partnership purposes.
ET-ETO Senior Notes Offering Exchange
In October 2017, ETEMarch 2019, ETO issued $1approximately $4.21 billion aggregate principal amount of senior notes to settle and exchange approximately 97% of ET’s outstanding senior notes. In connection with this exchange, ETO issued $1.14 billion aggregate principal amount of 7.50% senior notes due 2020, $995 million 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 portion2023, $1.13 billion aggregate principal amount of the outstanding indebtedness under ETE’s term loan facility5.875% senior notes due 2024 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.
ETP Senior Notes Redemption
In October 2017, ETP redeemed all of the outstanding $500$956 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.2027.
ETPETO Senior Notes Offering and Redemption
In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP,January 2019, ETO issued $750 million aggregate principal amount of 4.00%4.50% senior notes due 2027 and2024, $1.50 billion aggregate principal amount of 5.40%5.25% senior notes due 2047.2029 and $1.75 billion aggregate principal amount of 6.25% senior notes due 2049. The $2.22$3.96 billion net proceeds from the offering were used to repay in full ET’s outstanding senior secured term loan, to redeem alloutstanding senior notes at maturity, to repay a portion of the $500borrowings under ETO’s revolving credit facility and for general partnership purposes.
Panhandle Senior Notes Redemption
In June 2019, Panhandle’s $150 million aggregate principal amount of ETLP’s 6.5%8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.
Bakken Senior Notes Offering
In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued $650 million aggregate principal amount of 3.625% senior notes due 2021,2022, $1.00 billion aggregate principal amount of 3.90% senior notes due 2024 and $850 million aggregate principal amount of 4.625% senior notes due 2029. The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.
Sunoco LP Senior Notes Offering
In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings outstanding under theits credit facility. In July 2019, Sunoco Logistics Credit FacilityLP completed an exchange of these notes for registered notes with substantially identical terms.
USAC Senior Notes Offering
In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior unsecured notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes.

ETP August 2017 Units Offering
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, 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.
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 obligations related to the divested retail 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, 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.
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.

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.
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.
Quarterly Cash Distribution
In October 2017, ETEJuly 2019, ET announced its quarterly distribution of $0.2950.3050 per unit ($1.181.22 annualized) on ETEET common units for the quarter ended SeptemberJune 30, 2017.2019.

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. It is unknown at this time what actions that the FERC will take, if any, following receipt of responses to the 2017 Tax Law NOI and any potential impacts from final rules or policy statements issued following the 2017 Tax Law NOI on the rates ETO can charge for FERC regulated transportation services.
Also included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. On July 18, 2018, the FERC issued a Final Rule adopting procedures that are generally the same as proposed in the NOPR with a few clarifications and modifications. With limited exceptions, the Final Rule requires all FERC regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to make an election on how to treat its existing rates. The Final Rule suggests that this information will allow the FERC and other stakeholders to evaluate the impacts of the Tax Act and the Revised Policy Statement on each individual pipeline’s rates. The Final Rule also requires that each FERC regulated natural gas pipeline select one of four options to address changes to the pipeline’s revenue requirements as a result of the tax reductions: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates to reflect the reduced tax rates, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. For the limited NGA Section 4 option, the FERC clarified that, notwithstanding the Revised Policy Statement, a pipeline organized as a master limited partnership does not need to eliminate its income tax allowance but, instead, can reduce its rates to reflect the reduction in the maximum corporate tax rate. Trunkline, ETC Tiger Pipeline, LLC and Panhandle filed their respective FERC Form No. 501-Gs on October 11, 2018. FEP, Lake Charles LNG and certain other operating subsidiaries filed their respective FERC Form No. 501-Gs on or about November 8, 2018, and Rover, FGT, Transwestern and MEP filed their respective FERC Form No. 501-Gs on or about December 6, 2018. 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.  An initial decision is expected to be issued in the first quarter of 2020. By order issued February 19, 2019, the FERC initiated a review of Southwest Gas Storage Company’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas Storage Company are just and reasonable and set the matter for hearing.  Southwest Gas Storage Company filed a cost and revenue study on May 6, 2019.  On July 10, 2019, Southwest Gas Storage Company filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. Sea Robin Pipeline Company filed a Section 4 rate case on November 30, 2018.  A procedural schedule was ordered with a hearing date in the 4th quarter of 2019.  Sea Robin Pipeline Company has reached a settlement of this proceeding, with a settlement filed July 22, 2019, pending further action by the Commission.
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 may 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 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 index to change transportation rates every year. Most of the adjustments are effective July 1 of each year. With respect to common carrier 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 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 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.
Results of Operations
We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment 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 value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiariesunconsolidated affiliates based on 100%our proportionate ownership.
Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section below titled “Segment Operating Results.” Total Segment Adjusted EBITDA, as presented below, is equal to the consolidated measure of Adjusted EBITDA, which 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. Our definition of operations.total or consolidated Adjusted EBITDA is consistent with the definition of Segment Adjusted EBITDA above.

Consolidated Results

Three Months Ended
September 30,		   Nine Months Ended
September 30,		  Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2017 2016 Change 2017 2016 Change2019 2018 Change 2019 2018 Change
Segment Adjusted EBITDA:                      
Investment in ETP$1,744
 $1,390
 $354
 $4,757
 $4,172
 $585
Intrastate transportation and storage$290
 $208
 $82
 $542
 $400
 $142
Interstate transportation and storage460
 375
 85
 916
 741
 175
Midstream412
 414
 (2) 794
 791
 3
NGL and refined products transportation and services644
 461
 183
 1,256
 912
 344
Crude oil transportation and services751
 548
 203
 1,557
 1,012
 545
Investment in Sunoco LP199
 189
 10
 574
 512
 62
152
 140
 12
 305
 249
 56
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)
Investment in USAC105
 95
 10
 206
 95
 111
All other10
 21
 (11) 45
 64
 (19)
Total1,909
 1,504
 405
 5,226
 4,467
 759
2,824
 2,262
 562
 5,621
 4,264
 1,357
Depreciation, depletion and amortization(632) (548) (84) (1,840) (1,596) (244)(785) (694) (91) (1,559) (1,359) (200)
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)
Interest expense, net of interest capitalized(578) (510) (68) (1,168) (976) (192)
Impairment losses—
 —
 —
 (50) —
 (50)
Gains (losses) on interest rate derivatives(122) 20
 (142) (196) 72
 (268)
Non-cash compensation expense(29) (32) 3
 (58) (55) (3)
Unrealized gains (losses) on commodity risk management activities(76) (21) (55) 22
 (105) 127
(23) (265) 242
 26
 (352) 378
Losses on extinguishments of debt—
 —
 —
 (25) —
 (25)—
 —
 —
 (18) (106) 88
Inventory valuation adjustments141
 35
 106
 38
 203
 (165)4
 32
 (28) 97
 57
 40
Adjusted EBITDA related to unconsolidated affiliates(163) (168) 5
 (309) (324) 15
Equity in earnings of unconsolidated affiliates92
 49
 43
 228
 205
 23
77
 92
 (15) 142
 171
 (29)
Adjusted EBITDA related to unconsolidated affiliates(205) (157) (48) (554) (503) (51)
Adjusted EBITDA related to discontinued operations(92) (93) 1
 (253) (220) (33)—
 5
 (5) —
 25
 (25)
Impairment of investment in an unconsolidated affiliate—
 (308) 308
 —
 (308) 308
Other, net46
 4
 42
 111
 44
 67
37
 (15) 52
 20
 26
 (6)
Income (loss) before income tax benefit641
 (60) 701
 1,378
 626
 752
Income tax benefit(157) (89) (68) (97) (151) 54
Income from continuing operations before income tax expense1,242
 727
 515
 2,548
 1,443
 1,105
Income tax expense from continuing operations(34) (68) 34
 (160) (58) (102)
Income from continuing operations798
 29
 769
 1,475
 777
 698
1,208
 659
 549
 2,388
 1,385
 1,003
Income (loss) from discontinued operations, net of income taxes6
 12
 (6) (264) 24
 (288)
Loss from discontinued operations, net of income taxes—
 (26) 26
 —
 (263) 263
Net income$804
 $41
 $763
 $1,211
 $801
 $410
$1,208
 $633
 $575
 $2,388
 $1,122
 $1,266
See the detailed discussion of Segment Adjusted EBITDA in “Segment Operating Results” below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and ninesix months ended SeptemberJune 30, 20172019 compared to the same periodperiods last year increased primarily due to additional depreciation and amortization from assets recently placed in service. For the six months ended June 30, 2019, depreciation, depletion and amortization also increased due to the acquisition of USAC on April 2, 2018.

Interest Expense, Net.Net of Capitalized Interest. Interest expense, net of capitalized interest, for the three and ninesix months ended SeptemberJune 30, 20172019 increased primarily due to the following:
increases of $54 million and $141 million, respectively, recognized by the Partnership (excluding Sunoco LP and USAC, which are discussed below) primarily due to to increases in ETO’s long-term debt. The increases also reflect higher interest rates on floating rate borrowings, as well as the impact of reductions of $31 million and $67 million, respectively, in capitalized interest due to the completion of major projects in 2018;
an increase of $4$7 million of expense recognized by Sunoco LP for the three months ended SeptemberJune 30, 2017 compared to the same period in the prior year2019 recognized by USAC primarily due to higher interest rates on Sunoco LP’s borrowings under its revolving credit facility that Sunoco LP entered intosenior notes issuance in September 2014March 2019 and an increase of $51$36 million of expense for the ninesix months ended SeptemberJune 30, 2017 compared to the same period in the prior year2019 primarily due to the issuanceconsolidation of Sunoco LP’s

$800 million 6.250% senior notes onUSAC beginning April 7, 2016, as well as2, 2018, the increase in borrowings under Sunoco LP’s revolving credit facility;date ET obtained control of USAC; and
increases of $22$7 million and $71$15 million, respectively, of expense recognized by ETPSunoco LP primarily attributablerelated to increasesan increase in Sunoco LP’s total long-term debt, includingdebt.
Impairment Losses. For the Dakota Accesssix months ended ended June 30, 2019, Sunoco LP recognized an asset impairment of $47 million on assets held for sale related to its Fulton, New York ethanol plant, and ETCO term loans that became effective in August 2016.USAC recognized an asset impairment of $3 million related to certain compression equipment. There was no impairment for the three months ended June 30, 2019.
LossesGains (Losses) on Interest Rate Derivatives. Derivatives. Losses on interest rate derivatives during the three and ninesix months ended SeptemberJune 30, 2017 and 20162019 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 “Segment Operating Results” below.
Losses on Extinguishments of Debt. Losses on extinguishments of debt for the segment results below.six months ended June 30, 2018 resulted from Sunoco LP’s senior note and term loan redemption in January 2018.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded during the three and nine months ended September 30, 2017 and 2016, 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.were disposed of in January 2018.
Other, net. Includes amortization of regulatory assets and other income and expense amounts.
Income Tax (Expense) Benefit.Expense. 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 SeptemberJune 30, 2017,2019 compared to the Partnership recognized a $154 million deferredsame period in the prior year, income tax gain resulting from internal restructuring among its subsidiaries that resultedexpense decreased due to higher state tax expense in a change in tax status for one of the subsidiaries.prior period. For the three and ninesix months ended SeptemberJune 30, 2016,2019 compared to the Partnership’ssame period last year, income tax benefitexpense increased primarily resulted from losses among the Partnership’s consolidateddue to an increase in income before tax expense at our corporate subsidiaries.


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,		  
 2019 2018 Change 2019 2018 Change
Equity in earnings of unconsolidated affiliates:           
Citrus$39
 $33
 $6
 $71
 $60
 $11
FEP14
 13
 1
 28
 27
 1
MEP7
 8
 (1) 14
 17
 (3)
Other17
 38
 (21) 29
 67
 (38)
Total equity in earnings of unconsolidated affiliates$77
 $92
 $(15) $142
 $171
 $(29)
            
Adjusted EBITDA related to unconsolidated affiliates (1):
           
Citrus$87
 $85
 $2
 $168
 $160
 $8
FEP18
 18
 —
 37
 37
 —
MEP20
 20
 —
 39
 42
 (3)
Other38
 45
 (7) 65
 85
 (20)
Total Adjusted EBITDA related to unconsolidated affiliates$163
 $168
 $(5) $309
 $324
 $(15)
            
Distributions received from unconsolidated affiliates:           
Citrus$39
 $27
 $12
 $74
 $73
 $1
FEP16
 15
 1
 33
 32
 1
MEP15
 18
 (3) 26
 31
 (5)
Other42
 21
 21
 58
 42
 16
Total distributions received from unconsolidated affiliates$112
 $81
 $31
 $191
 $178
 $13
(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
InvestmentWe 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 ETPdeciding 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. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.
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.
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.
Following is a reconciliation of our segment margin to operating income, as reported in the Partnership’s consolidated statements of operations:
 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
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Segment margin:       
Intrastate transportation and storage$365
 $267
 $649
 $438
Interstate transportation and storage493
 378
 991
 743
Midstream614
 593
 1,191
 1,146
NGL and refined products transportation and services764
 587
 1,469
 1,187
Crude oil transportation and services909
 442
 1,995
 1,010
Investment in Sunoco LP269
 310
 639
 606
Investment in USAC150
 147
 299
 147
All other48
 57
 90
 152
Intersegment eliminations(37) (6) (42) (17)
Total segment margin3,575
 2,775
 7,281
 5,412
        
Less:       
Operating expenses792
 772
 1,600
 1,496
Depreciation, depletion and amortization785
 694
 1,559
 1,359
Selling, general and administrative179
 183
 326
 331
Impairment losses—
 —
 50
 —
Operating income$1,819
 $1,126
 $3,746
 $2,226
Segment Adjusted EBITDA
Intrastate Transportation and Storage
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2019 2018 Change 2019 2018 Change
Natural gas transported (BBtu/d)12,115
 10,327
 1,788
 12,049
 9,802
 2,247
Withdrawals from storage natural gas inventory (BBtu)—
 —
 —
 —
 17,703
 (17,703)
Revenues$765
 $813
 $(48) $1,621
 $1,688
 $(67)
Cost of products sold400
 546
 (146) 972
 1,250
 (278)
Segment margin365
 267
 98
 649
 438
 211
Unrealized (gains) losses on commodity risk management activities(26) (8) (18) (16) 45
 (61)
Operating expenses, excluding non-cash compensation expense(47) (51) 4
 (89) (90) 1
Selling, general and administrative expenses, excluding non-cash compensation expense(7) (7) —
 (13) (13) —
Adjusted EBITDA related to unconsolidated affiliates5
 7
 (2) 11
 20
 (9)
Segment Adjusted EBITDA$290
 $208
 $82
 $542
 $400
 $142
Volumes. For the three months ended SeptemberJune 30, 20172019 compared to the same period last year, transported volumes increased primarily due to the impact of the Red Bluff Express pipeline coming online in May 2018, as well as the impact of favorable market pricing spreads.
For the six months ended compared to the same period last year, transported volumes increased primarily due to the impact of reflecting RIGS as a consolidated subsidiary beginning in April 2018 and the impact of the Red Bluff Express pipeline coming online in May 2018, as well as the impact of favorable market pricing spreads.
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,		  
 2019 2018 Change 2019 2018 Change
Transportation fees$148
 $134
 $14
 $302
 $251
 $51
Natural gas sales and other (excluding unrealized gains and losses)173
 108
 65
 293
 199
 94
Retained fuel revenues (excluding unrealized gains and losses)12
 13
 (1) 23
 26
 (3)
Storage margin (excluding unrealized gains and losses)6
 4
 2
 15
 7
 8
Unrealized gains (losses) on commodity risk management activities26
 8
 18
 16
 (45) 61
Total segment margin$365
 $267
 $98
 $649
 $438
 $211
Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETPour intrastate transportation and storage segment increased due to the net impactimpacts of the following:

an increase of $30$65 million in ETP’s intrastate transportationrealized natural gas sales and storage operations resulting from an increase of $29 millionother 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 pipelines 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;
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;activity; and
an increase of approximately $20$14 million in ETP’s all other operations,transportation fees primarily due to an increasenew contracts, as well as the impact of $25 millionthe Red Bluff Express pipeline coming online 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 byMay 2018.
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, 20172019 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETPour intrastate transportation and storage segment increased due to the net impactimpacts of the following:
•
an increase of $94 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity;
•
an increase of $27 million in transportation fees, excluding the impact of consolidating RIGS as discussed below, primarily due to new contracts, as well as the impact of the Red Bluff Express pipeline coming online in May 2018;
•
a net increase of $11 million due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, retained fuel revenues and operating expenses of $24 million, $2 million, and $6 million, respectively, and a decrease of $9 million in Adjusted EBITDA related to unconsolidated affiliates; and
•
an increase of $8 million in realized storage margin primarily due to a $7 million increase in realized derivative gains and a $1 million increase in storage fees; partially offset by
a decrease of $3 million in retained fuel revenues primarily due to lower natural gas pricing.
Interstate Transportation and Storage
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2019 2018 Change 2019 2018 Change
Natural gas transported (BBtu/d)10,825
 8,707
 2,118
 11,177
 8,457
 2,720
Natural gas sold (BBtu/d)17
 17
 —
 18
 17
 1
Revenues$493
 $378
 $115
 $991
 $743
 $248
Operating expenses, excluding non-cash compensation, amortization and accretion expenses(138) (110) (28) (284) (209) (75)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses(18) (17) (1) (32) (35) 3
Adjusted EBITDA related to unconsolidated affiliates125
 123
 2
 244
 239
 5
Other(2) 1
 (3) (3) 3
 (6)
Segment Adjusted EBITDA$460
 $375
 $85
 $916
 $741
 $175
Volumes. For the three months ended June 30, 2019 compared to the same period last year, transported volumes reflected an increase of $19 million in ETP’s intrastate transportation and storage operations resulting from a $63 million increase due 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 operations primarily due to a $151 million increase in non-fee based margins due to higher realized crude oil 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;
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 expenses2,118 BBtu/d 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 fromfollowing: the Rover pipeline being placed fully in-service in partial serviceNovember 2018; production increases in August 2017the Haynesville Shale and by lower operating expensesdeliveries to intrastate markets resulting in increased deliveries off of our Tiger pipeline; and selling, generalincreased utilization of higher contracted capacity on the Panhandle 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; andTrunkline pipelines.
a decrease of approximately $32 million in ETP’s all other operations, primarily due to a decrease of $66 million relatedFor the six months ended June 30, 2019 compared to the termination of ETP’s management fees paid by ETE that ended in 2016 andsame period last year, transported volumes reflected an increase of $39 million2,720 BBtu/d as a result of the following: the Rover pipeline being placed fully in-service in transaction related expenses partially offset by an increaseNovember 2018; production increases in the Haynesville Shale and deliveries to intrastate markets resulting in increased deliveries off of $35 million in Adjusted EBITDA relatedour Tiger pipeline; increased utilization of higher contracted capacity on the Panhandle and Trunkline pipelines; fewer supply interruptions due to unconsolidated affiliates,maintenance performed on third-party production assets connected to our Sea Robin pipeline; and higher utilization of our Transwestern pipeline system due to improved market conditions primarily comprising increases of $29 millionfor transportation 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 relatedWest Texas to ETP’s compression operations.Southern California markets.
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, 20172019 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
an increase of $69 million from placing the Rover pipeline fully in-service, resulting in an increase of $101 million in revenues, partially offset by an increase of $32 million in operating expenses;
•
increases of $5 million and $3 million from higher utilization of our Transwestern and Trunkline pipeline systems, respectively;
•
an increase of $3 million for additional gas processing revenues on our Panhandle system;
•
an increase of $3 million from additional volume delivered from our Sea Robin pipeline as a result of fewer third-party supply interruptions; and

•
an increase of $2 million in Adjusted EBITDA from unconsolidated affiliates primarily due to new fixed transportation contracts on Citrus.
Segment Adjusted EBITDA. For the six months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
•
an increase of $129 million from placing the Rover pipeline fully in-service, resulting in an increase of $208 million in revenues, partially offset by an increase of $79 million in operating expenses;
•
an increase of $18 million from the Transwestern pipeline due to higher utilization as a result of more favorable market conditions;
•
an increase of $11 million on the Panhandle pipeline system primarily from additional gas processing revenues;
•
an increase of $7 million from additional volume delivered from the Sea Robin pipeline as a result of fewer third-party supply interruptions compared to the prior period;
•
increases of $4 million and $4 million from higher utilization of the Tiger and Trunkline pipeline systems, respectively; and
•
an increase of $5 million in Adjusted EBITDA from unconsolidated affiliates primarily due to new fixed transportation contracts on Citrus; partially offset by
•
a decrease of $6 million in other Adjusted EBITDA, including a $2 million decrease due to higher project-related expenses and a decrease of $1 million due to insurance reimbursements recovered in the prior period.
Midstream
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2019 2018 Change 2019 2018 Change
Gathered volumes (BBtu/d)13,148
 11,576
 1,572
 12,934
 11,442
 1,492
NGLs produced (MBbls/d)565
 513
 52
 564
 508
 56
Equity NGLs (MBbls/d)30
 31
 (1) 33
 30
 3
Revenues$1,198
 $1,874
 $(676) $2,916
 $3,488
 $(572)
Cost of products sold584
 1,281
 (697) 1,725
 2,342
 (617)
Segment margin614
 593
 21
 1,191
 1,146
 45
Operating expenses, excluding non-cash compensation expense(189) (169) (20) (372) (333) (39)
Selling, general and administrative expenses, excluding non-cash compensation expense(23) (20) (3) (42) (40) (2)
Adjusted EBITDA related to unconsolidated affiliates9
 9
 —
 15
 16
 (1)
Other1
 1
 —
 2
 2
 —
Segment Adjusted EBITDA$412
 $414
 $(2) $794
 $791
 $3
Volumes. For the three and six months ended June 30, 2019 compared to the same periods last year, gathered volumes and NGL production increased primarily due to increases in the Northeast, North Texas, South Texas, Permian and Ark-La-Tex regions, partially offset by smaller declines in the Mid-Continent/Panhandle regions.

Segment Margin. The table below presents the components of our midstream segment margin.  For the prior periods included in the table below, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect the reclassification of certain contractual minimum fees, in order to conform to the current period classification.  For the three and six months ended June 30, 2018, a total of $2 million and $6 million, respectively, was reclassified from fee-based margin to non-fee-based margin.
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2019 2018 Change 2019 2018 Change
Gathering and processing fee-based revenues$502
 $451
 $51
 $976
 $868
 $108
Non-fee-based contracts and processing112
 142
 (30) 215
 278
 (63)
Total segment margin$614
 $593
 $21
 $1,191
 $1,146
 $45
Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased slightly due to the net effects of the following:
a decrease of $30 million in non-fee-based margin due to lower NGL prices of $35 million and lower gas prices of $15 million, partially offset by the impact of increased throughput volume in the Permian region of $20 million;
•
an increase of $20 million in operating expenses due to an increase of $10 million in outside services, $7 million in maintenance project costs, and $3 million in employee costs; and
•
an increase of $3 million in selling, general and administrative expenses due to an increase in allocated overhead and an insurance payment received in the second quarter of 2018; partially offset by
an increase of $51 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions, offset by declines in the Mid-Continent/Panhandle regions.
Segment Adjusted EBITDA. For the six months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effects of the following:
•
an increase of $108 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions, offset by declines in the Mid-Continent/Panhandle regions; partially offset by
a decrease of $63 million in non-fee-based margin due to lower NGL prices of $72 million and lower gas prices of $23 million, partially offset by the impact of increased throughput volume in the North Texas, South Texas and Permian regions of $32 million;
•
an increase of $39 million in operating expenses due to increases of $20 million in outside services, $7 million in maintenance project costs, $7 million in employee costs; and $5 million in office and materials expenses; and
•
an increase of $2 million in selling, general and administrative expenses due to an insurance payment received in the second quarter of 2018.


NGL and Refined Products Transportation and Services
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2019 2018 Change 2019 2018 Change
NGL transportation volumes (MBbls/d)1,305
 967
 338
 1,241
 951
 290
Refined products transportation volumes (MBbls/d)628
 637
 (9) 623
 629
 (6)
NGL and refined products terminal volumes (MBbls/d)988
 789
 199
 938
 746
 192
NGL fractionation volumes (MBbls/d)701
 473
 228
 690
 473
 217
Revenues$2,612
 $2,568
 $44
 $5,643
 $5,114
 $529
Cost of products sold1,848
 1,981
 (133) 4,174
 3,927
 247
Segment margin764
 587
 177
 1,469
 1,187
 282
Unrealized losses on commodity risk management activities39
 13
 26
 96
 —
 96
Operating expenses, excluding non-cash compensation expense(155) (141) (14) (304) (280) (24)
Selling, general and administrative expenses, excluding non-cash compensation expense(26) (17) (9) (45) (35) (10)
Adjusted EBITDA related to unconsolidated affiliates21
 19
 2
 39
 40
 (1)
Other1
 —
 1
 1
 —
 1
Segment Adjusted EBITDA$644
 $461
 $183
 $1,256
 $912
 $344
Volumes. For the three and six months ended June 30, 2019 compared to the same periods last year, NGL transportation volumes increased as a result of placing Mariner East 2 pipeline in service and higher throughput volumes on our Texas NGL pipeline system resulting primarily from increased production in the Permian and North Texas regions.
Refined products transportation volumes decreased slightly for the three and six months ended June 30, 2019 compared to the same periods last year primarily due to refinery turnarounds in the Northeast and Midwest regions.
NGL and refined products terminal volumes increased for the three and six months ended June 30, 2019 compared to the same periods last year primarily at Marcus Hook due to the initiation of service on our Mariner East 2 pipeline which commenced operations in the fourth quarter of 2018, an increase in volumes loaded at our Nederland terminal due to increased export demand and higher throughput volumes at our refined product terminals in the Northeast.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased for the three and six months ended June 30, 2019 compared to the same periods last year primarily due to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, 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,		  
 2019 2018 Change 2019 2018 Change
Transportation margin$422
 $290
 $132
 $785
 $556
 $229
Fractionators and refinery services margin174
 128
 46
 360
 262
 98
Terminal services margin146
 91
 55
 263
 185
 78
Storage margin53
 48
 5
 109
 104
 5
Marketing margin8
 43
 (35) 48
 80
 (32)
Unrealized losses on commodity risk management activities(39) (13) (26) (96) —
 (96)
Total segment margin$764
 $587
 $177
 $1,469
 $1,187
 $282
Segment Adjusted EBITDA. For the three months ended June 30, 2019 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 $132 million in transportation margin primarily due to a $67 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $55 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $7 million increase due to higher throughput volumes received from the Barnett region and a $3 million increase due to higher throughput volumes received from the Eagle Ford region;
•
an increase of $55 million in terminal services margin primarily due to a $51 million increase at Marcus Hook resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018 and a $3 million increase due to higher throughput at our refined product terminals in the Northeast;
•
an increase of $46 million in fractionation and refinery services margin primarily due to a $50 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $3 million decrease primarily resulting from a reclassification between our fractionation and storage margins; and
•
an increase of $5 million in storage margin primarily due to a $3 million increase resulting from a reclassification between our storage and fractionation margins and a $2 million increase from throughput pipeline fees collected at our Mont Belvieu storage facility; partially offset by
a decrease of $35 million in marketing margin primarily due to a decrease of $16 million from the write down of the value of stored NGL inventory, as well as lower optimization gains due to less favorable market conditions;
•
an increase of $14 million in operating expenses primarily due to a $4 million increase resulting from to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, an aggregate increase of $7 million in ad valorem and employee expenses on our terminal and fractionation assets, and a $2 million increase in allocated costs; and
•
an increase of $9 million in selling, general and administrative expenses primarily due to a $4 million increase in allocated overhead costs, a $2 million increase in legal fees, a $1 million increase in employee costs and a $1 million increase in insurance expenses.



Segment Adjusted EBITDA. For the six months ended June 30, 2019 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 $229 million in transportation margin primarily due to a $123 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $93 million increase due to the the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $14 million increase due to higher throughput volumes from the Barnett region and a $7 million increase due to higher throughput from the Eagle Ford region. These increases were partially offset by a decrease resulting from Mariner East 1 system downtime;
•
an increase of $98 million in fractionation and refinery services margin primarily due to a $109 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. The increase was partially offset by a $7 million decrease resulting from a reclassification between our fractionation and storage margins and a $5 million decrease in refinery services margin primarily due to lower pricing spreads;
•
an increase $78 million in terminal services margin primarily due to a $73 million increase due to the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018 and a $5 million increase due to higher throughput at our refined product terminals in the Northeast; and
•
an increase of $5 million in storage margin primarily due to a $7 million increase resulting from a reclassification between our fractionation and storage margins. This increase was partially offset by a $2 million decrease from the expiration of and amendments to various refined products storage contracts; partially offset by
•
a decrease of $32 million in marketing margin primarily due to the write-down of the value of stored NGL inventory, as well lower optimization gains due to less favorable market conditions;
•
an increase of $24 million in operating expenses primarily due to a $5 million increase in costs to operate our fractionators due to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and an aggregate increase of $13 million in ad valorem and employee expenses on our terminal and fractionation assets, and a $3 million increase in product losses and a $2 million increase in materials purchased; and
•
an increase of $10 million in selling, general and administrative expenses primarily due to a $3 million increase in allocated overhead costs, a $3 million increase in legal fees, a $2 million increase in insurance expenses and a $2 million increase in employee costs.
Crude Oil Transportation and Services
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2019 2018 Change 2019 2018 Change
Crude transportation volumes (MBbls/d)4,728
 4,242
 486
 4,626
 4,036
 590
Crude terminals volumes (MBbls/d)2,383
 2,103
 280
 2,235
 2,022
 213
Revenues$5,046
 $4,803
 $243
 $9,232
 $8,548
 $684
Cost of products sold4,137
 4,361
 (224) 7,237
 7,538
 (301)
Segment margin909
 442
 467
 1,995
 1,010
 985
Unrealized (gains) losses on commodity risk management activities11
 262
 (251) (98) 305
 (403)
Operating expenses, excluding non-cash compensation expense(150) (144) (6) (300) (271) (29)
Selling, general and administrative expenses, excluding non-cash compensation expense(20) (20) —
 (40) (42) 2
Adjusted EBITDA related to unconsolidated affiliates1
 8
 (7) (1) 10
 (11)
Other—
 —
 —
 1
 —
 1
Segment Adjusted EBITDA$751
 $548
 $203
 $1,557
 $1,012
 $545
Volumes. For the three and six months ended June 30, 2019 compared to the same periods last year, crude transportation and terminal volumes benefited from an increase in barrels through our existing Texas pipelines and our Bakken pipeline.

Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
an increase of $216 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $142 million increase from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region, a $75 million increase from higher throughput on the Bakken pipeline, and a $9 million increase from higher throughput, ship loading and tank rental fees at our Nederland terminal; partially offset by a $10 million decrease (excluding a net change of $251 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from non-cash inventory valuation adjustments; partially offset by
•
an increase of $6 million in operating expenses primarily due to a $14 million increase in throughput-related costs on existing assets, partially offset by an $8 million decrease in ad valorem taxes and management fees; and
•
a decrease of $7 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.
Segment Adjusted EBITDA. For the six months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
•
an increase of $582 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $284 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers, a $166 million favorable variance resulting from increased throughput on the Bakken pipeline, a $114 million increase (excluding a net change of $403 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from improved basis differentials between the Permian and Bakken producing regions to our Nederland terminal on the Texas Gulf Coast, and an $18 million increase primarily from higher throughput, ship loading and tank rental fees at our Nederland terminal; and
•
a decrease of $2 million in selling, general and administrative expenses primarily due to a $3 million decrease in management fees, and a $2 million decrease in overhead allocations, partially offset by a $3 million increase in insurance and employee costs; partially offset by
•
an increase of $29 million in operating expenses primarily due to a $44 million increase in throughput related costs on existing assets, partially offset by a $15 million decrease in ad valorem taxes and management fees; and
•
a decrease of $11 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.
Investment in Sunoco LP
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2019 2018 Change 2019 2018 Change
Revenues$4,475
 $4,607
 $(132) $8,167
 $8,356
 $(189)
Cost of products sold4,206
 4,297
 (91) 7,528
 7,750
 (222)
Segment margin269
 310
 (41) 639
 606
 33
Unrealized (gains) losses on commodity risk management activities3
 —
 3
 (3) —
 (3)
Operating expenses, excluding non-cash compensation expense(89) (105) 16
 (187) (218) 31
Selling, general and administrative expenses, excluding non-cash compensation expense(31) (31) —
 (55) (63) 8
Inventory valuation adjustments(4) (32) 28
 (97) (57) (40)
Adjusted EBITDA related to discontinued operations—
 (5) 5
 —
 (25) 25
Other4
 3
 1
 8
 6
 2
Segment Adjusted EBITDA$152
 $140
 $12
 $305
 $249
 $56

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 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:
a decrease of $16 million in operating expenses primarily as a result of lower salaries and benefits, maintenance, utilities, property tax, and environmental expenses as well as $7 million of acquisition costs in the prior periods; and
an increase of $5 million in wholesale motor fuel revenueAdjusted EBITDA from discontinued operations due to a higher sales price per wholesale motor fuel gallon, and an increaseSunoco LP’s retail divestment in wholesale motor fuel gallons soldJanuary 2018; partially offset by higher cost of products sold, excluding a $56 million favorable inventory adjustment change from 2016;
•
a decrease of $10 million in segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities, primarily due to a decrease in gross profit per gallon sold primarily as a result of an $8 million one-time charge related to a reserve for an open contractual dispute.
a net increase in other revenue consisting of merchandise, rental income and retail motor fuel of $8 million; and
a decrease in selling, general and administrative expenses of $21 million primarily due to higher costs in 2016 related to relocation, employee termination, 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.
Segment Adjusted EBITDA.For the ninesix months ended SeptemberJune 30, 20172019 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 aggregate decrease of $39 million in expenses primarily due to the conversion of 207 retail sites to commission agent sites in April 2018; and
•
an increase of $25 million in Adjusted EBITDA from discontinued operations due to Sunoco LP’s retail divestment in January 2018; partially offset by
•
a decrease of $10 million in segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities, primarily due to a decrease in gross profit per gallon sold primarily as a result of a $8 million one-time charge related to a reserve for an open contractual dispute.
Investment in USAC

an increase
 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2019 2018 Change 2019 2018 Change
Revenues$174
 $167
 $7
 $345
 $167
 $178
Cost of products sold24
 20
 4
 46
 20
 26
Segment margin150
 147
 3
 299
 147
 152
Operating expenses, excluding non-cash compensation expense(32) (38) 6
 (67) (38) (29)
Selling, general and administrative expenses, excluding non-cash compensation expense(13) (19) 6
 (26) (19) (7)
Other—
 5
 (5) —
 5
 (5)
Segment Adjusted EBITDA$105
 $95
 $10
 $206
 $95
 $111
The Investment in wholesale motor fuel revenueUSAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to a higher sales price per wholesale motor fuel gallon, and an increase in wholesale motor fuel gallons sold offset by higher costthe net impacts of products soldthe following:
•
a decrease of $6 million in operating expenses primarily due to a decrease of ad valorem taxes between periods as well as refunds received in the current period related to prior period ad valorem taxes;
•
a decrease of $6 million in selling, general administrative expenses primarily related to decreases of $4 million in transaction-related expenses and $2 million in employee expenses; and
•
an increase of $3 million in segment margin primarily due to an increase in demand for compression services resulting in an increase in average revenue generating horsepower.
Amounts reflected above for the six months ended June 30, 2019 reflects the consolidated results of USAC. Changes between periods are primarily due to an unfavorable inventory adjustment changes;the consolidation of USAC beginning April 2, 2018, the date ET obtained control of USAC.
a decrease in selling, general and administrative expenses of $35 million primarily due to higher costs in 2016 related to relocation, employee termination, 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; and
an increase in adjusted EBITDA from discontinued operations of $33 million primarily due to an increase of $73 million in the gross profit offset by an increase of $48 million in selling, general and administrative expenses related to discontinued operations; partially offset by
an increase in other operating expenses of $11 million primarily attributable to the acquisition of the fuels business from Emerge Energy Services LP 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 LNGAll Other
Three Months Ended
September 30,		   Nine Months Ended
September 30,		  Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2017 2016 Change 2017 2016 Change2019 2018 Change 2019 2018 Change
Revenues$49
 $50
 $(1) $148
 $148
 $—
$391
 $502
 $(111) $888
 $1,073
 $(185)
Cost of products sold343
 445
 (102) 798
 921
 (123)
Segment margin48
 57
 (9) 90
 152
 (62)
Unrealized (gains) losses on commodity risk management activities(4) (2) (2) (5) 2
 (7)
Operating expenses, excluding non-cash compensation expense(6) (4) (2) (15) (13) (2)(6) (10) 4
 (13) (41) 28
Selling, general and administrative, excluding non-cash compensation expense—
 (1) 1
 (2) (2) —
Selling, general and administrative expenses, excluding non-cash compensation expense(23) (28) 5
 (34) (48) 14
Adjusted EBITDA related to unconsolidated affiliates2
 2
 —
 1
 (1) 2
Other and eliminations(7) 2
 (9) 6
 —
 6
Segment Adjusted EBITDA$43
 $45
 $(2) $131
 $133
 $(2)$10
 $21
 $(11) $45
 $64
 $(19)
Lake Charles LNG derivesAmounts reflected in our all other segment primarily include:
our natural gas marketing operations;
our wholly-owned natural gas compression operations;
a noncontrolling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent to the August 2018 reorganization, ETO holds an approximately 7.4% interest in PES and no longer reflects PES as an affiliate; and
our investment in coal handling facilities.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of its revenue from a long-term contract with BG Group plc.the following:
•
a decrease of $7 million from power trading activities;
•
a decrease of $10 million due to lower revenue from our compressor equipment business;
•
a decrease of $4 million in optimized gains on residue gas sales; and
•
a decrease of $2 million from settled derivatives; partially offset by
•
an increase of $13 million in storage optimization gains.
Segment Adjusted EBITDA. For the six months ended June 30, 2019 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 $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;
•
a decrease of $2 million due to residue gas sales; partially offset by
•
an increase of $12 million in gains from park and loan and storage activity.
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.
ETPETO
ETP’sETO’s ability to satisfy its obligations and pay distributions to its unitholdersthe Parent Company 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 ETP’sETO’s management.
ETO currently expects capital expenditures in 2019 to be within the following ranges:
 Growth Maintenance
 Low High Low High
Intrastate transportation and storage$125
 $150
 $35
 $40
Interstate transportation and storage (1)
350
 375
 135
 140
Midstream800
 850
 160
 165
NGL and refined products transportation and services2,800
 2,850
 90
 100
Crude oil transportation and services (1)
325
 350
 100
 110
All other (including eliminations)200
 225
 50
 55
Total capital expenditures$4,600
 $4,800
 $570
 $610
(1)
Includes capital expenditures related to ETO’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.
The assets used in ETP’sETO’s 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, ETPETO does not have any

significant financial commitments for maintenance capital expenditures in its businesses. From time to time ETPETO experiences increases in pipe costs due to a number of reasons,factors, including but not limited to, delays from 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, ETPETO’s control; however, ETO has included these factors in its anticipated growth capital expenditures for each year.
ETPETO generally funds its maintenance capital expenditures and distributions with cash flows from operating activities. ETPETO generally fundsexpects to fund 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.
Excluding acquisitions, Sunoco LP currently expects to spend approximately $150$100 million on growth capital and $70$40 million on maintenance capital for the full year 2017.2019.
USAC
USAC currently plans to spend approximately $25 million in maintenance capital expenditures during 2019, including parts consumed from inventory.
Without giving effect to any equipment USAC may acquire pursuant to any future acquisitions, it currently has budgeted between $140 million and $150 million in expansion capital expenditures during 2019. As of June 30, 2019, USAC has binding commitments to purchase $82 million of additional compression units and serialized parts, all of which USAC expects to be delivered throughout 2019 and 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, 20172019 compared to ninesix months ended SeptemberJune 30, 20162018. Cash provided by operating activities during 20172019 was $3.30$3.89 billion as compared to $2.22$3.16 billion for 2016. Net2018 and income from continuing operations was $1.21$2.39 billion and $801 million$1.39 billion for 20172019 and 2016,2018, respectively. The difference between net income and the net cash provided by operating activities for the ninesix months ended SeptemberJune 30, 2017 and 2016,2019 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 $274 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 $1.63 billion.
The non-cash activity in 20172019 and 20162018 consisted primarily of depreciation, depletion and amortization of $1.84$1.56 billion and $1.60$1.36 billion, respectively, equity in earningsnon-cash compensation expense of unconsolidated affiliates of $228$58 million and $205$55 million, respectively, inventory valuation adjustments of $38$97 million and $203$57 million, respectively, and deferred income taxes of $120$138 million and $139$71 million, respectively. Non-cash activity also included losses on extinguishments of debt in 2019 and 2018 of $18 million and $106 million, respectively, impairment losses of $50 million in 2019.
Unconsolidated affiliate activity in 2019 and 2018 consisted of equity in earnings of $142 million and $171 million, respectively, and unit-based compensation expensecash distributions received of $76$170 million and $46$138 million, respectively.
Cash paid for interest, net of capitalized interest, capitalized, was $1.41$1.09 billion and $1.43 billion$893 million for the ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, respectively.
Capitalized interest was $177$94 million and $148$161 million for the ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, 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, 20172019 compared to ninesix months ended SeptemberJune 30, 2016. 2018. Cash used in investing activities during 20172019 was $4.76$2.94 billion as compared to cash used in investing activities $6.08$3.14 billion for 2016.2018. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 20172019 were $6.10 billion. This compares$2.78 billion compared to total$3.48 billion for 2018. Additional detail related to our capital expenditures (excludingis provided in the allowancetable below. During 2019, we also 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 acquistions. During 2018, we also received $461 million of net cash proceeds related to the USAC acquisition and paid $143 million in cash for all 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) for 2016 of $5.88 billion. During the ninesix months ended SeptemberJune 30, 2017, we had proceeds from transactions of $1.4 billion.2019:
 Capital Expenditures Recorded During Period
 Growth Maintenance Total
Intrastate transportation and storage (1)
$8
 $28
 $36
Interstate transportation and storage91
 52
 143
Midstream361
 67
 428
NGL and refined products transportation and services1,074
 34
 1,108
Crude oil transportation and services159
 39
 198
Investment in Sunoco LP47
 10
 57
Investment in USAC84
 15
 99
All other (including eliminations)72
 16
 88
Total capital expenditures$1,896
 $261
 $2,157
(1)
For the six months ended June 30, 2019, growth capital expenditures for the intrastate transportation and storage segment reflect the proceeds received from the sale of a noncontrolling interest in the Red Bluff Express pipeline, which was based on capital expenditures from prior periods.
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, 20172019 compared to ninesix months ended SeptemberJune 30, 2016.2018. Cash used in financing activities during 20172019 was $1.30 billion$926 million as compared to cash provided by financing activities of $3.92$2.58 billion for 2016. In 2017, ETE2018. During 2019, our subsidiaries received $2.20 billion$780 million in net proceeds from offerings of ETE common units and subsidiary common units as compared to $2.10 billion in 2016.units. In 2016, Sunoco Logistics2018, our subsidiaries received $1.31 billion$940 million in net proceeds from offerings of their commonsubsidiary units. During 2017,2019, we had a consolidated net increase in our debt level of $1.40 billion as$538 million compared to a net increasedecrease of $4.33$1.34 billion for 2016.2018. In 2017,2019 and 2018, we paid net proceeds on affiliates notes in the amountdebt issuance costs of $255 million. We have$87 million and $173 million, respectively.
In 2019, we paid distributions of $752$1.55 billion to our partners and our subsidiaries paid distributions of $813 million and $780to noncontrolling interests. In 2018, we paid distributions of $532 million to our partners in 2017 and in 2016, respectively. Ourour subsidiaries have paid distributions of $1.79 billion to noncontrolling interestinterests. In addition, our subsidiaries received capital contributions of $2.16$206 million in cash from noncontrolling interests in 2019 compared to $318 million in 2018.
Discontinued Operations
Cash flows from discontinued operations reflect cash flows related to Sunoco LP’s retail divestment.
Six months ended June 30, 2019 compared to six months ended June 30, 2018. There were no cash flows related to discontinued operations during 2019. Cash provided by discontinued operations during 2018 was $2.74 billion, resulting from cash used in operating activities of $478 million, cash provided by investing activities of $3.21 billion and $2.03 billionchanges in 2017 and 2016, respectively.cash included in current assets held for sale of $11 million.

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, 2019 December 31, 2018
Parent Company Indebtedness:   
ET Senior Notes due October 2020$52
 $1,187
ET Senior Notes due March 20236
 1,000
ET Senior Notes due January 202423
 1,150
ET Senior Notes due June 202744
 1,000
ET Senior Secured Term Loan—
 1,220
Subsidiary Indebtedness:   
ETO Senior Notes (1)
36,117
 28,755
Transwestern Senior Notes575
 575
Panhandle Senior Notes236
 385
Bakken Senior Notes2,500
 —
Sunoco LP Senior Notes and lease-related obligations2,912
 2,307
USAC Senior Notes1,475
 725
Credit facilities and commercial paper:   
ETO $5.00 billion Revolving Credit Facility due December 2023 (2)
2,368
 3,694
Bakken Project $2.50 billion Credit Facility due August 2019—
 2,500
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023117
 700
USAC $1.60 billion Revolving Credit Facility due April 2023363
 1,050
Other long-term debt4
 7
Unamortized premiums, net of discounts and fair value adjustments7
 21
Deferred debt issuance costs(293) (248)
Total debt46,506
 46,028
Less: current maturities of long-term debt7
 2,655
Long-term debt, less current maturities$46,499
 $43,373
(1) 
Includes $2.06
The increase in ETO Senior Notes during six months ended June 30, 2019 includes $4.21 billion issued in connection with the ET-ETO senior notes exchange and $777$4.00 billion issued in the January 2019 senior notes offering, both of which are discussed below. The June 30, 2019 balance also includes $250 million aggregate principal amount of commercial paper outstanding at September5.50% senior notes due February 15, 2020 that was classified as long-term as of June 30, 20172019 as management has the intent and December 31, 2016, respectively.ability to refinance the borrowing on a long-term basis.
(2) 
Includes $50 million$2.36 billion and $2.34 billion of commercial paper outstanding at June 30, 2019 and 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 2017.2018, respectively.
Recent Transactions
ET Term Loan Facility
On January 15, 2019, ET paid in full all outstanding borrowings under its 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 notes was released in accordance with the terms of the applicable indentures governing such senior notes.
ET-ETO Senior Notes Exchange
In February 2019, ETO commenced offers to exchange all of ET’s outstanding senior notes for senior notes issued by ETO.  Approximately 97% of ET’s outstanding senior notes were tendered and Term Loanaccepted, and substantially all the exchanges settled on March 25, 2019. Following the exchange, the ET senior notes that were not tendered and remain outstanding as of June 30, 2019 were as follows:
Energy Transfer Equity, L.P. Senior Notes Offering $52 million aggregate principal amount of 7.50% senior notes due 2020;
In October 2017, ETE issued $1 billion$5 million 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.2023;

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.
ETP Senior Notes Redemption
In October 2017, ETP redeemed all of the outstanding $500$23 million aggregate principal amount of ETLP’s 6.50%5.875% senior notes due July 20212024; and all of the outstanding $700
$44 million aggregate principal amount of ETLP’s 5.50% senior notes due April 2023. 2027.
In connection with the exchange, ETO issued approximately $4.21 billion aggregate principal amount of the following senior notes:
$1.14 billion aggregate principal amount of 7.50% senior notes due 2020;
$995 million aggregate principal amount of 4.25% senior notes due 2023;
$1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and
$956 million aggregate principal amount of 5.50% senior notes due 2027.
The aggregate amountsenior notes were registered under the Securities Act of 1933 (as amended).  ETO 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 on the senior notes is payable upon maturity and interest is paid semi-annually.
The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to redeem theseany future subordinated debt ETO may incur.  The notes including call premiums, was approximately $1.23 billion.
ETP Senior Notes Offering 
In September 2017,of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a subsidiarysenior unsecured basis so long as it guarantees any of ETP,our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes.
ETO Senior Notes Offering and Redemption
In January 2019, ETO issued $750the following senior notes:
$750 million aggregate principal amount of 4.00%4.50% senior notes due 2027 and $1.502024;
$1.50 billion aggregate principal amount of 5.40%5.25% senior notes due 2047. 2029; and
$1.75 billion aggregate principal amount of 6.25% senior notes due 2049.
The $2.22senior notes were registered under the Securities Act of 1933 (as amended).  ETO 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 on the senior notes is payable upon maturity and interest is paid semi-annually.
The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur.  The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes.
The $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the $500following:
ETO’s $400 million aggregate principal amount of ETLP’s 6.5%9.70% senior notes due 2021,March 15, 2019;
ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and
Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019.
Panhandle Senior Notes Redemption
In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.
Bakken Senior Notes Offering
In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued the following senior notes related to the Bakken pipeline:
$650 million aggregate principal amount of 3.625% senior notes due 2022;
$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and
$850 million aggregate principal amount of 4.625% senior notes due 2029.

The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.
Sunoco LP Senior Notes Offering
In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings outstanding under theits credit facility. In July 2019, Sunoco Logistics Credit Facility (described below)LP completed an exchange of these notes for registered notes with substantially identical terms.
USAC Senior Notes Offering
In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior unsecured notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes.
Credit Facilities and Commercial Paper
Parent CompanyETO 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, 2017,2019, the Sunoco LogisticsETO Five-Year Credit Facility had $35 million$2.37 billion of outstanding borrowings.borrowings, $2.36 billion of which was commercial paper. The amount available for future borrowings was $2.56 billion after taking into account letters of credit of $77 million. The weighted average interest rate on the total amount outstanding as of June 30, 2019 was 3.05%.
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 29, 2019. As of June 30, 2019, 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, 2017,2019, the Sunoco LP credit facilityCredit Facility had $644$117 million of outstanding borrowings and $19$8 million in standby letters of credit. As of June 30, 2019 Sunoco LP had $1.38 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, 20172019 was $847 million.4.41%.
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, $2.5 billion was outstanding under this credit facility.
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017,2019, the PennTex RevolvingUSAC Credit Facility had $363 million of outstanding borrowings and no outstanding letters of credit. As of June 30, 2019, USAC had $1.24 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $439 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of June 30, 2019 was repaid and terminated.5.10%.
Covenants Related to Our Credit Agreements
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of SeptemberJune 30, 2017.2019.
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 distributions
Distributions 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, 20162018 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, 2018 February 8, 2019 February 19, 2019 $0.3050
March 31, 2019 May 7, 2019 May 20, 2019 0.3050
June 30, 2019 August 6, 2019 August 19, 2019 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, 2018 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 (2)
December 31, 2018 February 1, 2019 February 15, 2019 $31.25
 $33.125
 $0.4609
 $0.4766
 $—
March 31, 2019 May 1, 2019 May 15, 2019 —
 —
 0.4609
 0.4766
 —
June 30, 2019 August 1, 2019 August 15, 2019 31.25
 33.125
 0.4609
 0.4766
 0.5806
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 E Preferred Unit distributions related to the period ended June 30, 2019 represent a prorated initial distribution.
Cash Distributions Paid by Sunoco LP
Following are distributionsDistributions declared and/or paid by Sunoco LP subsequent to December 31, 2016:2018 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, 2018 February 6, 2019 February 14, 2019 $0.8255
March 31, 2019 May 7, 2019 May 15, 2019 0.8255
June 30, 2019 August 6, 2019 August 14, 2019 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 subsequent to which they relate):December 31, 2018 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, 2018 January 28, 2019 February 8, 2019 $0.5250
March 31, 2019 April 29, 2019 May 10, 2019 0.5250
June 30, 2019 July 29, 2019 August 9, 2019 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 22, 2019. 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.
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.
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 sites that have been classified as held for sale; thus, a key assumption in the goodwill impairment test was the assumed sales proceeds (less the related costs 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 from that sales process to develop the assumed sales proceeds for those sites. While management believes that the assumed sales proceeds for these remaining held-for-sale sites arelease accounting.

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 assumption usedRECENT ACCOUNTING PRONOUNCEMENTS
See Note 1 in the impairment test. Subsequent 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 goodwillaccompanying unaudited interim consolidated financial statements included in the Aloha and Wholesale reporting units, which goodwill balances total $112 million and $732 million, respectively, and which were not classified as held“Item 1. Financial Statements” in this Quarterly Report for sale, no impairments were deemed necessary during the three months ended June 30, 2017. Management does not believe that the goodwill associated with either of these reporting units or the remaining goodwill of $188 million within the retail reporting unit is at significant risk of impairment, and the goodwill will continue to be subjected to annual goodwill impairment testing on October 1.information regarding recent accounting pronouncements.
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, 2016,2018 filed with the SEC on February 23, 2018, 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, 2016.2018. Since December 31, 20162018, 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, 2019 December 31, 2018
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)
13,038
 $1
 $—
 16,845
 $7
 $1
Fixed Swaps/Futures1,297,500
 $—
 $—
 (682,500) $—
 $—
775
 —
 —
 468
 —
 —
Basis Swaps IFERC/NYMEX (1)
(15,810,000) (4) —
 2,242,500
 (1) —
Options – Puts13,000,000
 —
 —
 —
 —
 —
—
 —
 —
 10,000
 —
 —
Power (Megawatt):                      
Forwards665,040
 1
 2
 391,880
 (1) 1
2,554,800
 9
 6
 3,141,520
 6
 8
Futures(213,840) —
 1
 109,564
 —
 —
1,095,558
 (1) —
 56,656
 —
 —
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 – Puts175,200
 —
 —
 18,400
 —
 —
Options – Calls317,600
 —
 —
 284,800
 1
 —
(Non-Trading)                      
Natural Gas (MMBtu):           
Natural Gas (BBtu):           
Basis Swaps IFERC/NYMEX67,500
 (3) 2
 10,750,000
 2
 —
(23,115) (12) 6
 (30,228) (52) 13
Swing Swaps IFERC91,897,500
 (2) —
 (5,662,500) (1) 1
8,480
 (2) —
 54,158
 12
 —
Fixed Swaps/Futures(20,220,000) 1
 7
 (52,652,500) (27) 19
(3,505) —
 1
 (1,068) 19
 1
Forward Physical Contracts(140,937,993) 3
 43
 (22,492,489) 1
 —
(22,542) 4
 6
 (123,254) (1) 32
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(1,612) (32) 35
 (2,135) 67
 67
Refined Products (MBbls) – Futures(126) (3) 8
 (1,403) (8) 6
Crude (MBbls) – Forwards/Swaps18,670
 39
 9
 20,888
 (60) 29
Corn (thousand bushels)(2,605) 1
 1
 (1,920) —
 1
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
(31,703) 2
 —
 (17,445) (4) —
Fixed Swaps/Futures(41,102,500) 5
 12
 (36,370,000) (26) 14
(31,703) 12
 8
 (17,445) (10) 6
(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, 20172019, we and our subsidiaries had $10.47$3.45 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$34 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 
Type(1)
 Notional Amount Outstanding
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
Term 
Type(1)
 June 30, 2019 December 31, 2018
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
$—
 $400
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 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
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
 —
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
 Pay a floating rate and receive a fixed rate of 1.42% —
 300
(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.
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$315 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.2019. 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, 20172019 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
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 the three months ended SeptemberJune 30, 20172019 that 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 22, 2019 and Note 11 – 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, 2017.2019.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed below were decided against us, it would not be material to our financial position, results of operations or 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 instructions to Form 10-Q, matters disclosed in this Part II, Item 1 include any reportable legal proceeding (i) that has been terminated during the period covered by this report, (ii) that became a reportable event during the period covered by this report, or (iii) for which there has been a material development during the period covered by this report.
On February 8, 2019, PADEP filed a Petition to Enforce the Compliance Order with Pennsylvania’s Commonwealth Court. The court issued an Order on February 14, 2019 requiring the submission of an answer to the Petition on or before March 12, 2019, and scheduled a hearing on the Petition for March 26, 2019.  On March 12, 2019, ETC Northeast answered the Petition.  ETC Northeast and PADEP have since agreed to a Stipulated Order regarding the issues raised in the Compliance Order, which obviated the need for a hearing. The Commonwealth Court approved the Stipulated Order on March 26, 2019.  On February 8, 2019, PADEP also issued a Permit Hold on any requests for approvals/permits or permit amendments made by us or any of our subsidiaries for any projects in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board on March 11, 2019. On May 14, 2019, PADEP issued a Compliance Order related to impacts to streams and wetlands. The Partnership filed an appeal of the Streams and Wetlands Compliance Order on June 14, 2019. The Partnership continues to work through these issues with PADEP.
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, hydrostatic permit violations involving the alleged discharge of effluent with greater levels of pollutants than the permits allowed and allegedly not properly sampling or monitoring effluent for required parameters or reporting those alleged violations, and engaging in construction activities without an effective water quality certification. Although Rover has successfully completed clean-up mitigation for the alleged violations to Ohio EPA’s satisfaction, the Ohio EPA has broughtproposed penalties and restitution of approximately $2.6 million in connection with the alleged violations and is seeking certain injunctive relief. The Ohio Attorney General filed a federal court action against SPLPcomplaint in the Court of Common Pleas of Stark County, Ohio to obtain these remedies and Mid-Valley for violations ofthat case remains pending and is in the Clean Water Act (“CWA”).early stages. Rover and other defendants filed several motions to dismiss and Ohio EPA filed a motion in opposition. The United States’ complaint alleges that SPLP and Mid-Valley violated Sections 311(b)(7)(A) and 301(a) of the CWA when, during three separate releases, pipelines operated by SPLP and owned by SPLP or Mid-Valley Pipeline Company discharged oil. See 33 U.S.C. §§ 1311(a) and 1321(b)(7)(A). In particular, the three releases at issue occurred (1) on February 23, 2013, 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 discussionsState’s opposition to resolve these matters.
Mont Belvieu received a Notice of Enforcement (“NOE”) with an Agreed Order from the Texas Commission on Environmental Quality and has a pending settlement for $0.01 million.  The NOEthose motions 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”)filed on October 12, 2017 for allegations2018. Rover and other defendants filed their replies on November 2, 2018. On March 13, 2019, the court granted Rover and the other Defendants’ motion to dismiss on all counts.
On April 10, 2019, the Ohio EPA filed a notice of violations of New Mexico air regulations related to Jal #3 facilities. This order is a combination of Notice of Violation REG-0569-1402-R1appeal 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 NMEDfiled their opening brief on June 6, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. The alleged violation occurred during the period of January 1, 2017 through September 11, 2017. The NMED is offering to settle 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.13, 2019. The timing or outcome of this matter cannot be reasonably be determined at this timetime; however, the Partnership doeswe do not expect there to be a material impact onto our business or results of operations.operations, cash flows or financial position.
In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment 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 implemented the suggestions in the assessment and additional voluntary protocols. The FERC authorized Rover to resume HDD activities at all sites and all Rover HDD activities are now complete. The pipeline is now in service.
In late 2016, FERC Enforcement Staff began a non-public investigation of Rover’s removal of the Stoneman House, a potential historic structure, in connection with Rover’s application for permission to construct a new interstate natural gas pipeline and related facilities. In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River HDD. Rover and the Partnership are cooperating with the investigations. Enforcement Staff has provided Rover its non-public preliminary findings regarding those investigations. The company disagrees with those findings and intends to vigorously defend against any potential penalty. Given the stage of the proceedings, and the non-public nature of the investigation, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.

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 rupture occurred on the Noble to Douglas 8” pipeline in an area of external 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.
For a description of other legal proceedings, see Note 11 to our consolidated financial statements included in “Item 1. Financial Statements.”
ITEM 1A. RISK FACTORS
There have been no material changes from the risk factors described in “PartPart I, — Item 1A. Risk Factors” of our1A in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016 or from2018 filed with the risk factors described in “Part II — Item 1A. Risk Factors” of our Quarterly ReportSEC on Form 10-Q for the quarter ended March 31, 2017.February 22, 2019.
ITEM 5. OTHER INFORMATION
Effective August 6, 2019, the Board of Directors of LE GP, LLC, the general partner of Energy Transfer LP (the “Partnership”), adopted and executed Amendment No. 7 (the “LP Agreement Amendment”) to the Third Amended and Restated Agreement of Limited Partnership of the Partnership to insert certain provisions relating to examinations of the Partnership’s affairs by tax authorities.  The LP Agreement Amendment is attached hereto as Exhibit 3.10 and is incorporated herein by reference.

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
4.1
Ninth Supplemental Indenture, dated as of March 25, 2019, between Energy Transfer LP and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed March 27, 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*XBRL Instance Document
101.SCH* 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 Document
* 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 8, 2019By: /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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