Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
ýQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20172018
or
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-31219
ENERGY TRANSFER PARTNERS,OPERATING, L.P.
(Exact name of registrant as specified in its charter)
Delaware 73-1493906
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
8111 Westchester Drive, Suite 600, Dallas, Texas 75225
(Address of principal executive offices) (zip code)
(214) 981-0700
(Registrant’s telephone number, including area code)

Energy Transfer Partners, L.P.

(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  ý    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).    Yes  ý    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 filer ý 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
At November 3, 2017, the registrant had 1,155,493,524 Common Units outstanding.
 

FORM 10-Q
ENERGY TRANSFER PARTNERS,OPERATING, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
 
  
 
  
  
  
  
  
  
  
  
  
  
 
  
  
  
  


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Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners,Operating, L.P. (the “Partnership” or “ETP”) in periodic press releases and some oral statements of the Partnership’s officials 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,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partnerGeneral 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, projected or expected, forecasted, estimated or expressed 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, 20162017 filed with the Securities and Exchange Commission on February 24, 2017 and Exhibit 99.3 to23, 2018, “Part II – Item 1A. Risk Factors,” in the Partnership’s CurrentQuarterly Report on Form 8-K10-Q for the quarter ended March 31, 2018 filed with the Securities and Exchange Commission on May 8, 2017.10, 2018 and “Part II – Item 1A. Risk Factors,” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed on August 9, 2018.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
 /d per day
   
AmeriGasAmeriGas Partners, L.P.
 
 AOCI accumulated other comprehensive income (loss)
    
 AROsBBtu asset retirement obligationsbillion British thermal units
 
Bblsbarrels
   
 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 used
   
 Capacity capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
    
 CDMCDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively
Citrus Citrus, LLC
    
 CrossCountryCrossCountry Energy, LLC
DOJ U.S.United States Department of Justice
    
 ETC CompressionETC Compression, LLC
EPA United States Environmental Protection Agency
ETC FEPETC Fayetteville Express Pipeline, LLC
ETC MEPETC Midcontinent Express Pipeline, L.L.C.
    
 ETC OLP La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
    
 ETC TigerETC Tiger Pipeline, LLC
ETEEnergy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC for the periods presented herein
ET InterstateEnergy Transfer Interstate Holdings, LLC
ET RoverET Rover Pipeline LLC
ETLP Credit FacilityEnergy Transfer, LP’s $3.75 billion revolving credit facility
ETP GP Energy Transfer Partners GP, L.P., the general partner of ETP
    


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 ETP Holdco ETP Holdco Corporation
    
 ETP LLC Energy Transfer Partners, L.L.C., the general partner of ETP GP
   
 Exchange Act Securities Exchange Act of 1934
ExxonMobil
Exxon Mobil Corporation

    
 FEP Fayetteville Express Pipeline LLC
    
 FERC Federal Energy Regulatory Commission
    
 FGT Florida Gas Transmission Company, LLC
    
 GAAP accounting principles generally accepted in the United States of America
    
 HPC RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
    
 IDRs incentive distribution rights


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Lake Charles LNGLake Charles LNG Company, LLC
Legacy ETP Preferred Unitslegacy ETP Series A cumulative convertible preferred units
    
 LIBOR London Interbank Offered Rate
    
 MEPMidcontinent Express Pipeline LLC
MBbls thousand barrels
    
 MMBtuMEP million British thermal units
MMcfmillion cubic feetMidcontinent 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
    
 Panhandle Panhandle Eastern Pipe Line Company, LP and its subsidiaries
    
 PCBspolychlorinated biphenyls
PennTex PennTex Midstream Partners, LP
    
 PES Philadelphia Energy Solutions a refining joint venture
Preferred UnitsETP Series A cumulative convertible preferred units
    
 Regency Regency Energy Partners LP
    
 Retail Holdings ETP Retail Holdings, LLC, a wholly-owned subsidiary of Sunoco, Inc.
    
 RIGSRegency Intrastate Gas LP
Rover Rover Pipeline LLC, a subsidiary of ETP
    
 Sea RobinSEC Sea Robin Pipeline Company, LLC, a subsidiary of PanhandleSecurities and Exchange Commission
    
 SECSeries A Preferred Units Securities and Exchange Commission6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series B Preferred Units6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series C Preferred Units7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series D Preferred Units7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
    
 Sunoco Logistics Sunoco Logistics Partners L.P.
    
 Transwestern Transwestern Pipeline Company, LLC
    
 Trunkline Trunkline Gas Company, LLC, a subsidiary of Panhandle
USACUSA Compression Partners, LP
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt 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).adjustments. Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.


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PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENERGY TRANSFER PARTNERS,OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
ASSETS      
Current assets:      
Cash and cash equivalents$379
 $360
$379
 $306
Accounts receivable, net3,083
 3,002
3,671
 3,946
Accounts receivable from related companies335
 209
333
 318
Inventories1,591
 1,712
1,507
 1,589
Income taxes receivable151
 128
169
 135
Derivative assets40
 20
93
 24
Other current assets201
 298
201
 210
Total current assets5,780
 5,729
6,353
 6,528
      
Property, plant and equipment65,735
 58,220
70,966
 67,699
Accumulated depreciation and depletion(8,763) (7,303)(10,416) (9,262)
56,972
 50,917
60,550
 58,437
      
Advances to and investments in unconsolidated affiliates4,221
 4,280
3,599
 3,816
Other non-current assets, net752
 672
863
 758
Intangible assets, net5,379
 4,696
4,925
 5,311
Goodwill3,907
 3,897
2,866
 3,115
Total assets$77,011
 $70,191
$79,156
 $77,965

ENERGY TRANSFER PARTNERS,OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
LIABILITIES AND EQUITY      
Current liabilities:      
Accounts payable$3,410
 $2,900
$3,381
 $4,126
Accounts payable to related companies204
 43
287
 209
Derivative liabilities128
 166
338
 109
Accrued and other current liabilities2,434
 1,905
2,603
 2,143
Current maturities of long-term debt710
 1,189
2,649
 407
Total current liabilities6,886
 6,203
9,258
 6,994
      
Long-term debt, less current maturities33,630
 31,741
31,198
 32,687
Long-term notes payable – related company
 250
Non-current derivative liabilities132
 76
57
 145
Deferred income taxes4,374
 4,394
2,845
 2,883
Other non-current liabilities1,111
 952
1,100
 1,084
      
Commitments and contingencies
 

 
Preferred Units
 33
Redeemable noncontrolling interests21
 15
22
 21
      
Equity:      
Limited Partners:   
Series A Preferred Unitholders944
 944
Series B Preferred Unitholders547
 547
Series C Preferred Unitholders439
 
Series D Preferred Unitholders436
 
Common Unitholders25,628
 26,531
General Partner252
 206
340
 244
Limited Partners:   
Common Unitholders26,400
 14,946
Class H Unitholder
 3,480
Class I Unitholder
 2
Accumulated other comprehensive income14
 8
8
 3
Total partners’ capital26,666
 18,642
28,342
 28,269
Noncontrolling interest4,191
 7,885
6,334
 5,882
Total equity30,857
 26,527
34,676
 34,151
Total liabilities and equity$77,011
 $70,191
$79,156
 $77,965

ENERGY TRANSFER PARTNERS,OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)millions)
(unaudited)
Three Months Ended
September 30,
 Nine Months Ended
September 30,
Three Months Ended
September 30,
 Nine Months Ended
September 30,
2017 2016 2017 20162018 2017* 2018 2017*
REVENUES:              
Natural gas sales$1,098
 $1,069
 $3,132
 $2,602
$1,026
 $1,098
 $3,112
 $3,132
NGL sales1,750
 1,249
 4,782
 3,339
2,695
 1,750
 6,866
 4,782
Crude sales2,273
 1,649
 6,751
 4,572
3,841
 2,381
 11,336
 7,268
Gathering, transportation and other fees1,027
 986
 3,118
 2,991
1,579
 1,027
 4,440
 3,118
Refined product sales334
 177
 1,109
 656
382
 334
 1,234
 1,109
Other491
 401
 1,552
 1,141
118
 383
 343
 1,035
Total revenues6,973
 5,531
 20,444
 15,301
9,641
 6,973
 27,331
 20,444
COSTS AND EXPENSES:              
Cost of products sold4,876
 3,844
 14,582
 10,280
6,745
 4,922
 19,873
 14,595
Operating expenses571
 475
 1,603
 1,359
632
 571
 1,863
 1,603
Depreciation, depletion and amortization596
 503
 1,713
 1,469
636
 596
 1,827
 1,713
Selling, general and administrative105
 71
 335
 226
123
 105
 347
 335
Total costs and expenses6,148
 4,893
 18,233
 13,334
8,136
 6,194
 23,910
 18,246
OPERATING INCOME825
 638
 2,211
 1,967
1,505
 779
 3,421
 2,198
OTHER INCOME (EXPENSE):              
Interest expense, net(367) (345) (1,052) (981)(387) (352) (1,091) (1,020)
Equity in earnings of unconsolidated affiliates127
 65
 139
 260
113
 127
 147
 139
Impairment of investment in an unconsolidated affiliate
 (308) 
 (308)
Losses on interest rate derivatives(8) (28) (28) (179)
Gain on Sunoco LP common unit repurchase
 
 172
 
Loss on deconsolidation of CDM
 
 (86) 
Gains (losses) on interest rate derivatives45
 (8) 117
 (28)
Other, net72
 52
 169
 96
21
 57
 127
 137
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)649
 74
 1,439
 855
1,297
 603
 2,807
 1,426
Income tax expense (benefit)(112) (64) 22
 (131)(61) (112) (32) 22
NET INCOME761
 138
 1,417
 986
1,358
 715
 2,839
 1,404
Less: Net income attributable to noncontrolling interest110
 64
 243
 231
223
 110
 557
 266
NET INCOME ATTRIBUTABLE TO PARTNERS651
 74
 1,174
 755
$1,135
 $605
 $2,282
 $1,138
General Partner’s interest in net income270
 220
 727
 740
Class H Unitholder’s interest in net income
 93
 98
 257
Class I Unitholder’s interest in net income
 2
 
 6
Common Unitholders’ interest in net income (loss)$381
 $(241) $349
 $(248)
NET INCOME (LOSS) PER COMMON UNIT:       
Basic$0.33
 $(0.33) $0.35
 $(0.36)
Diluted$0.33
 $(0.33) $0.34
 $(0.36)
* As adjusted. See Note 1.

ENERGY TRANSFER PARTNERS,OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
(unaudited)
Three Months Ended
September 30,
 Nine Months Ended
September 30,
Three Months Ended
September 30,
 Nine Months Ended
September 30,
2017 2016 2017 20162018 2017* 2018 2017*
Net income$761
 $138
 $1,417
 $986
$1,358
 $715
 $2,839
 $1,404
Other comprehensive income (loss), net of tax:              
Change in value of available-for-sale securities2
 
 5
 5
2
 2
 
 5
Actuarial gain (loss) relating to pension and other postretirement benefit plans5
 
 2
 (3)
 5
 (2) 2
Foreign currency translation adjustments
 
 
 (1)
Change in other comprehensive income from unconsolidated affiliates
 2
 (1) (9)2
 
 9
 (1)
7
 2
 6
 (8)4
 7
 7
 6
Comprehensive income768
 140
 1,423
 978
1,362
 722
 2,846
 1,410
Less: Comprehensive income attributable to noncontrolling interest110
 64
 243
 231
223
 110
 557
 266
Comprehensive income attributable to partners$658
 $76
 $1,180
 $747
$1,139
 $612
 $2,289
 $1,144
* As adjusted. See Note 1.

ENERGY TRANSFER PARTNERS,OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 20172018
(Dollars in millions)
(unaudited)
  Limited Partners      Limited Partners        
General Partner Common Units Class H Units Class I Units Accumulated Other Comprehensive Income Noncontrolling Interest TotalSeries A Preferred Units Series B Preferred Units Series C Preferred Units Series D Preferred Units Common Units General Partner AOCI Noncontrolling Interest Total
Balance, December 31, 2016$206
 $14,946
 $3,480
 $2
 $8
 $7,885
 $26,527
Balance, December 31, 2017$944
 $547
 $
 $
 $26,531
 $244
 $3
 $5,882
 $34,151
Distributions to partners(681) (1,765) (95) (2) 
 
 (2,543)(44) (27) (10) 
 (1,975) (1,080) 
 
 (3,136)
Distributions to noncontrolling interest
 
 
 
 
 (306) (306)
 
 
 
 
 
 
 (536) (536)
Units issued for cash
 2,162
 
 
 
 
 2,162

 
 436
 431
 58
 
 
 
 925
Sunoco Logistics Merger
 9,459
 (3,483) 
 
 (5,976) 
Capital contributions from noncontrolling interest
 
 
 
 
 1,907
 1,907

 
 
 
 
 
 
 438
 438
Sale of Bakken Pipeline interest
 1,260
 
 
 
 740
 2,000
Acquisition of PennTex noncontrolling interest
 (48) 
 
 
 (232) (280)
Repurchases of common units
 
 
 
 (24) 
 
 
 (24)
Other comprehensive income, net of tax
 
 
 
 6
 
 6

 
 
 
 
 
 7
 
 7
Other, net
 37
 
 
 
 (70) (33)(1) 
 (1) (1) 41
 (17) (2) (7) 12
Net income727
 349
 98
 
 
 243
 1,417
45
 27
 14
 6
 997
 1,193
 
 557
 2,839
Balance, September 30, 2017$252
 $26,400
 $
 $
 $14
 $4,191
 $30,857
Balance, September 30, 2018$944
 $547
 $439
 $436
 $25,628
 $340
 $8
 $6,334
 $34,676

ENERGY TRANSFER PARTNERS,OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)
Nine Months Ended
September 30,
Nine Months Ended
September 30,
2017 20162018 2017*
OPERATING ACTIVITIES      
Net income$1,417
 $986
$2,839
 $1,404
Reconciliation of net income to net cash provided by operating activities:      
Depreciation, depletion and amortization1,713
 1,469
1,827
 1,713
Deferred income taxes(1) (154)(17) (1)
Amortization included in interest expense5
 (16)
Inventory valuation adjustments(30) (143)
Unit-based compensation expense57
 60
Impairment of investment in an unconsolidated affiliate
 308
Non-cash compensation expense61
 57
Gain on Sunoco LP common unit repurchase(172) 
Loss on deconsolidation of CDM86
 
Distributions on unvested awards(21) (19)(24) (21)
Equity in earnings of unconsolidated affiliates(139) (260)(147) (139)
Distributions from unconsolidated affiliates319
 292
328
 319
Other non-cash(168) (230)(132) (163)
Net change in operating assets and liabilities, net of effects of acquisition185
 172
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations451
 168
Net cash provided by operating activities3,337
 2,465
5,100
 3,337
INVESTING ACTIVITIES      
Proceeds from Bakken Pipeline Transaction2,000
 
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction
 2,200
Cash proceeds from CDM contribution1,227
 
Cash proceeds from Sunoco LP common unit repurchase540
 
Cash proceeds from Bakken pipeline transaction
 2,000
Cash paid for acquisition of PennTex noncontrolling interest(280) 

 (280)
Cash paid for all other acquisitions(264) (159)(29) (264)
Capital expenditures, excluding allowance for equity funds used during construction(6,074) (5,787)(4,962) (6,074)
Contributions in aid of construction costs18
 44
95
 18
Contributions to unconsolidated affiliates(230) (47)(13) (230)
Distributions from unconsolidated affiliates in excess of cumulative earnings116
 112
62
 116
Proceeds from the sale of assets33
 6
13
 33
Change in restricted cash
 (8)
Other(6) (1)
 (6)
Net cash used in investing activities(4,687) (3,640)(3,067) (4,687)
FINANCING ACTIVITIES      
Proceeds from borrowings19,978
 13,073
16,930
 19,978
Repayments of long-term debt(18,487) (11,308)
Repayments of debt(16,520) (18,487)
Cash paid to affiliate notes(255) (1)
 (255)
Units issued for cash2,162
 794
Subsidiary units issued for cash
 1,305
Common units issued for cash58
 2,162
Preferred units issued for cash867
 
Capital contributions from noncontrolling interest919
 187
438
 919
Distributions to partners(2,543) (2,669)(3,136) (2,543)
Distributions to noncontrolling interest(306) (334)(536) (306)
Redemption of Preferred Units(53) 
Repurchases of common units(24) 
Redemption of Legacy ETP Preferred Units
 (53)
Debt issuance costs(50) (22)(42) (50)
Other4
 
5
 4
Net cash provided by financing activities1,369
 1,025
Increase (decrease) in cash and cash equivalents19
 (150)
Net cash (used in) provided by financing activities(1,960) 1,369
Increase in cash and cash equivalents73
 19
Cash and cash equivalents, beginning of period360
 527
306
 360
Cash and cash equivalents, end of period$379
 $377
$379
 $379
* As adjusted. See Note 1.

ENERGY TRANSFER PARTNERS,OPERATING, L.P. 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
Energy Transfer Partners,Operating, L.P. (“ETP”, formerly named “Sunoco Logistics Partners L.P.”, as discussed below) is a consolidated subsidiary of ETE. Energy Transfer LP. In October 2018, Energy Transfer Equity, L.P. (“ETE”) and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly-owned subsidiary of ETE in a unit-for-unit exchange (the “ETE-ETP Merger”). In connection with the transaction, ETP unitholders (other than ETE and its subsidiaries) received 1.28 common units of ETE for each common unit of ETP they owned.
Immediately prior to the closing of the ETE-ETP Merger, the following also occurred:
the IDRs in ETP were converted into 1,168,205,710 ETP common units; and
the general partner interest in ETP was converted to a non-economic general partner interest and ETP issued 18,448,341 ETP common units to ETP GP.
Following the closing of the ETE-ETP Merger, ETE changed its name to “Energy Transfer LP” and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on Friday, October 19, 2018. In addition, ETP changed its name to “Energy Transfer Operating, L.P.” For purposes of maintaining clarity, the following references are used herein:
References to “ETP” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the ETE-ETP Merger and Energy Transfer Operating, L.P. subsequent to the close of the ETE-ETP Merger; and
References to “ETE” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the ETE-ETP Merger and Energy Transfer LP subsequent to the close of the ETE-ETP 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 totransaction (the “Sunoco Logistics Merger”), with the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders receivedreceiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. UnderIn connection with the terms of the merger agreement,Sunoco Logistics Merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. Based on the number of Energy Transfer Partners, L.P. common units outstanding at 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 prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.
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.” For purposes of maintaining clarity, the following references are used herein:
References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;
References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and
References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.
The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes).
The Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.related name changes).
The consolidated financial statements of the Partnership presented herein include our operating subsidiaries (collectively, the “Operating Companies”), through which our activities are primarily conducted, as follows:
ETC OLP, Regency and PennTex, which are primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP and Regency own and operate, through their wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, West Virginia, DenverColorado and Ohio.


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ETEnergy Transfer Interstate Holdings, LLC, (“ETIH”) with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstatesales, which is the parent company of:
Transwestern, engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
ETC FEP,Fayetteville Express Pipeline, LLC, which directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.
ETC Tiger Pipeline, LLC, engaged in interstate transportation of natural gas.
CrossCountry Energy, LLC, which indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.


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ETC MEP,Midcontinent Express Pipeline, L.L.C., which directly owns a 50% interest in MEP.
ET Rover Pipeline, LLC, which ETIH directly owns a 50.1% interest in, which owns a 65% interest in the Rover pipeline.
ETC Compression, LLC, engaged in natural gas compression services and related equipment sales.
As discussed further in Note 2 below, in April 2018, we contributed certain assets to USAC.
ETP Holdco, which indirectly owns Panhandle and Sunoco, Inc. Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. Sunoco Inc. owned and operated retail marketing assets, which were contributed to Sunoco LP in March 2016. Subsequent to this transaction, Sunoco Inc.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. Subsequent to the Sunoco Logistics Merger, ETLPETP Holdco also holds an equity method investment in ETP through ETP Holdco’sits ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in theETP’s consolidated financial statements.
Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
Subsequent to the Sunoco Logistics Merger, ourOur consolidated financial statements reflect the following reportable business segments:
intrastate transportation and storage;
interstate transportation and storage;
midstream;
NGL and refined products transportation and services;
crude oil transportation and services; and
all other.
Prior periods have been retrospectively adjusted to reflect the impact of the Sunoco Logistics Merger on our reportable business segments.
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 of Energy Transfer Partners, L.P. for the year ended December 31, 2016,2017, included in Exhibit 99.1 to the Partnership’s CurrentAnnual Report on Form 8-K10-K filed with the SEC on August 14, 2017.February 23, 2018. 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 affiliates. These reclassifications had no impact on net income or total equity.
Use of Estimates
The unauditedhistorical common unit amounts presented in these consolidated financial statements have been preparedretrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in conformityconnection with GAAP, which includes the useSunoco Logistics Merger.
Change in Accounting Policy
Inventory Accounting Change
During the fourth quarter of estimates2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and assumptions made by managementNGLs associated with the legacy Sunoco Logistics business. Management believes that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist atweighted-average cost method is preferable to the date ofLIFO method as it more closely aligns the accounting policies across the consolidated financial statements. Althoughentity.


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these estimates are based on management’s available knowledgeAs a result of currentthis change in accounting policy, the consolidated statement of operations and expected future events, actual results could be different from those estimates.comprehensive income in prior periods have been retrospectively adjusted, as follows:
Recent Accounting Pronouncements
ASU 2014-09
 Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
 As Originally Reported Effect of Change As Adjusted As Originally Reported Effect of Change As Adjusted
Cost of products sold$4,876
 $46
 $4,922
 $14,582
 $13
 $14,595
Operating income825
 (46) 779
 2,211
 (13) 2,198
Income before income tax expense (benefit)649
 (46) 603
 1,439
 (13) 1,426
Net income761
 (46) 715
 1,417
 (13) 1,404
Net income attributable to partners651
 (46) 605
 1,174
 (36) 1,138
Comprehensive income768
 (46) 722
 1,423
 (13) 1,410
Comprehensive income attributable to partners658
 (46) 612
 1,180
 (36) 1,144
As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows:
 Nine Months Ended September 30, 2017
 As Originally Reported Effect of Change As Adjusted
Net income$1,417
 $(13) $1,404
Inventory valuation adjustments(30) 30
 
Net change in operating assets and liabilities, net of effects from acquisitions (change in inventories)185
 (17) 168
Revenue Recognition Standard
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“(“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership expects to adoptadopted 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.on January 1, 2018.
We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements.
We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of our reportable segments as well as the accounting for certain processing contracts in our midstream segment. 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 ofUpon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to contributionsdecreases in aidrevenue (with offsetting decreases to cost of construction costs (“CIAC”) arrangementssales) resulting from recognition of non-cash consideration as revenue when received and materialityas cost of anysales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related changes. While we do not expect any impacts to net income frommultiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the application of the standard to other transactions,evaluation performed, we have not concluded whether the application of the standard to CIAC transactions could impact net income.
We continue to assess the impact of the disclosure requirements under the new standardmade appropriate design 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 changesimplementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. We continue
Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to monitor additional authoritative or interpretive guidance relatedexisting contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018.
The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods.


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The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales and operating expenses. There were no material changes in the timing of recognition of revenue and therefore no material impacts to the balance sheet upon adoption.
The disclosure below shows the impact of adopting the new standard as it becomesduring the period of adoption compared to amounts that would have been reported under the Partnership’s previous revenue recognition policies:
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower) As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower)
Revenues:           
Natural gas sales$1,026
 $1,026
 $
 $3,112
 $3,112
 $
NGL sales2,695
 2,686
 9
 6,866
 6,839
 27
Crude sales3,841
 3,838
 3
 11,336
 11,326
 10
Gathering, transportation and other fees1,579
 1,783
 (204) 4,440
 4,977
 (537)
Refined product sales382
 381
 1
 1,234
 1,233
 1
Other118
 118
 
 343
 343
 
            
Costs and expenses:           
Cost of products sold$6,745
 $6,949
 $(204) $19,873
 $20,410
 $(537)
Operating expenses632
 619
 13
 1,863
 1,825
 38
Additional disclosures related to revenue are included in Note 11.
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 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.knowledge of current and expected future events, actual results could be different from those estimates.
Recent Accounting Pronouncements
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,The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria 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,sales-type and classification on the statement of cash flows. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements and related disclosures.
ASU 2016-16
direct financing leases. In October 2016,January 2018, the FASB issued Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory2018-01 (“ASU 2016-16”2018-01”), which requires that entities recognize the income tax consequences ofprovides an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update dooptional transition practical expedient to not change GAAP for the pre-tax effects of an intra-entity asset transferevaluate under Topic 810, Consolidation,842 existing or expired land easements that were not previously accounted for an intra-entity transferas leases under the existing lease guidance in Topic 840. The Partnership plans to elect the package of inventory. ASU 2016-16 is effectivetransition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment to retained earnings. The Partnership has performed several procedures to evaluate the impact of the adoption of this standard on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for fiscal years beginning after December 15, 2017,our leases in accordance with the new standard. However, we are still in the process of quantifying this impact. We expect that upon adoption most of the Partnership’s lease commitments will be recognized as right of use assets and interim periods within thoselease obligations.


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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 standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.
ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second 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, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.
ASU 2017-12
In August 2017, the FASB issued ASUAccounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2018-02
In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material.
2.ACQUISITIONS AND CONTRIBUTIONOTHER INVESTING TRANSACTIONS
RoverETE Contribution Agreementof Assets to ETP
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”), forImmediately prior to the purchase by Blackstone of a 49.9% interest in the holding company that owns 65%closing of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required BlackstoneETE-ETP Merger discussed in Note 1, ETE contributed the following to contribute, at closing, fundsETP:
2,263,158 common units representing limited partner interests in Sunoco LP to reimburse ETP in exchange for its pro rata share2,874,275 ETP common units;
100 percent of the Rover construction costs incurred by ETP throughlimited liability company interests in Sunoco GP LLC, the closing date, along with the paymentsole general partner 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 ETPSunoco LP, and 49.9% by Blackstone.
Permian Express Partners
In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“PEP”), a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, the Partnership 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 the Partnership’s ownership interest in PEP to approximately 88%. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflectedIDRs in Sunoco LP, to ETP in exchange for 42,812,389 ETP common units;
12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETP in exchange for 16,134,903 ETP common units; and
a 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC (collectively, “Lake Charles LNG and Other”) to ETP in exchange for 37,557,815 ETP common units.
ETP, Sunoco LP, USAC and Lake Charles LNG and Other are under common control of ETE; therefore, we expect to account for the contribution transactions at historical cost as a reorganization of entities under common control. Accordingly, beginning with the quarter ending December 31, 2018, ETP’s consolidated subsidiaryfinancial statements will be retrospectively adjusted to reflect consolidation of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in anSunoco LP and Lake Charles LNG and Other for all prior periods and consolidation of USAC subsequent to April 2, 2018 (the date ETE acquired USAC’s general partner).


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increaseThe following table summarizes the assets and liabilities of $988Sunoco LP, USAC and Lake Charles LNG and Other as of September 30, 2018, which amounts will be retrospectively consolidated in ETP’s consolidated balance sheets beginning with the quarter ending December 31, 2018, subject to the elimination of intercompany balances:
 Sunoco LP USAC Lake Charles LNG and Other
Current assets$1,331
 $230
 $28
Property, plant and equipment, net1,494
 2,541
 746
Goodwill1,534
 619
 184
Intangible assets655
 399
 35
Other non-current assets134
 25
 909
Total assets$5,148
 $3,814
 $1,902
      
Current liabilities$1,086
 $173
 $107
Long-term debt, less current maturities2,774
 1,731
 
Other non-current liabilities343
 6
 8
Preferred Units
 477
 
Net assets$945
 $1,427
 $1,787
The unaudited financial information in the table below summarizes the combined results of our operations and those of Sunoco LP, USAC and Lake Charles LNG and Other on a pro forma basis, to reflect the retrospective consolidation of those entities. The pro forma financial information is presented for informational purposes only and is not indicative of the results of operations that would have been achieved. The pro forma adjustments include the effect of intercompany revenue eliminations:
 Unaudited Pro Forma
 Nine Months Ended
September 30,
 2018 2017
Revenues$40,514
 $29,072
Net income attributable to partners$2,282
 $1,138
CDM Contribution
On April 2, 2018, ETP contributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019.
Prior to the CDM Contribution, the CDM entities were indirect wholly-owned subsidiaries of ETP. Beginning April 2018, ETP’s consolidated financial statements reflected an equity method investment in USAC. CDM’s assets and liabilities were not reflected as held for sale, nor were CDM’s results reflected as discontinued operations in these financial statements. At September 30, 2018, the carrying value of ETP’s investment in USAC was $385 million in noncontrolling interest,, which is reflected in “Capital contributionsthe all other segment. ETP recorded an $86 million loss on the deconsolidation of CDM including a $45 million accrual related to the indemnification of USAC related to an ongoing CDM sales and use tax audit.
In connection with the CDM Contribution, ETE acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC, and (ii) 12,466,912 USAC common units for cash consideration equal to $250 million.


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3.ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES
HPC
ETP previously owned a 49.99% interest in HPC, which owns RIGS.  In April 2018, ETP acquired the remaining 50.01% interest in HPC.  Prior to April 2018, HPC was reflected as an unconsolidated affiliate in ETP’s financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in ETP’s financial statements.
Sunoco LP
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from noncontrolling interest”the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.
As of September 30, 2018, ETP owned 26.2 million Sunoco LP common units representing 31.8% of Sunoco LP’s total outstanding common units. Our investment in Sunoco LP is reflected in the all other segment. As of September 30, 2018, the carrying value of our investment in Sunoco LP was $542 million.
Subsequent to the ETE-ETP Merger, ETP owns 28.5 million Sunoco LP common units. For the periods presented herein, ETP’s investment in Sunoco LP is reflected under the equity method of accounting; however, for periods subsequent to the ETE-ETP Merger, ETP will reflect Sunoco LP as a consolidated statementsubsidiary.
USAC
As of equity.September 30, 2018, ETP owned 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests in USAC. USAC provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. Our investment in USAC is reflected in the all other segment. As of September 30, 2018, the carrying value of our investment in USAC was $385 million.
Subsequent to the ETE-ETP Merger, ETP owns 39.7 million USAC common units and 6.4 million USAC Class B Units. For the periods presented herein, ETP’s investment in USAC is reflected under the equity method of accounting; however, for periods subsequent to the ETE-ETP Merger, ETP will reflect USAC as a consolidated subsidiary.
3.4.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.


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The net change in operating assets and liabilities (net of effects of acquisitions)acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:
Nine Months Ended
September 30,
Nine Months Ended
September 30,
2017 20162018 2017*
Accounts receivable$(77) $(595)$251
 $(77)
Accounts receivable from related companies46
 80
206
 46
Inventories150
 (299)48
 133
Other current assets37
 (135)(23) 37
Other non-current assets, net(89) (1)(99) (89)
Accounts payable96
 635
(177) 96
Accounts payable to related companies(11) 24
(199) (11)
Accrued and other current liabilities(26) 213
351
 (26)
Other non-current liabilities57
 31
21
 57
Derivative assets and liabilities, net2
 219
72
 2
Net change in operating assets and liabilities, net of effects of acquisitions$185
 $172
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations$451
 $168
* As adjusted. See Note 1.
Non-cash investing and financing activities are as follows:

Nine Months Ended
September 30,
Nine Months Ended
September 30,

2017 20162018 2017
NON-CASH INVESTING ACTIVITIES:      
Accrued capital expenditures$1,236
 $991
$1,026
 $1,236
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP
 194
Net gains from subsidiary common unit issuances
 34
USAC limited partner interests received in the CDM Contribution (see Note 2)411
 
NON-CASH FINANCING ACTIVITIES:      
Contribution of property, plant and equipment from noncontrolling interest$988
 $
$
 $988


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4.5.INVENTORIES
Inventories consisted of the following:
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
Natural gas and NGLs$609
 $699
Natural gas, NGLs and refined products$615
 $733
Crude oil696
 683
643
 551
Refined products69
 113
Spare parts and other217
 217
249
 305
Total inventories$1,591
 $1,712
$1,507
 $1,589
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
5.6.FAIR VALUE MEASURES
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of September 30, 2017 were $35.892018 was $34.39 billion and $34.34$33.85 billion, respectively. As of December 31, 2016,2017, the aggregate fair value and carrying amount of


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our consolidated debt obligations were $33.85was $34.28 billion and $32.93$33.09 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the 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 nine months ended September 30, 2017,2018, no transfers were made between any levels within the fair value hierarchy.


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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 September 30, 20172018 and December 31, 20162017 based on inputs used to derive their fair values:
  Fair Value Measurements at
September 30, 2017
  Fair Value Measurements at
September 30, 2018
Fair Value Total Level 1 Level 2Fair Value Total Level 1 Level 2
Assets:          
Commodity derivatives:          
Natural Gas:          
Basis Swaps IFERC/NYMEX$16
 $16
 $
$48
 $48
 $
Swing Swaps IFERC2
 
 2
1
 
 1
Fixed Swaps/Futures28
 28
 
25
 25
 
Forward Physical Swaps3
 
 3
Forward Physical Contracts12
 
 12
Power:          
Forwards11
 
 11
36
 
 36
Futures1
 1
 
Options – Puts1
 1
 
1
 1
 
Natural Gas Liquids – Forwards/Swaps213
 213
 
Refined Products – Futures2
 2
 
Crude – Futures2
 2
 
NGLs – Forwards/Swaps476
 476
 
Total commodity derivatives279
 263
 16
599
 550
 49
Other non-current assets28
 18
 10
Total assets$279
 $263
 $16
$627
 $568
 $59
Liabilities:          
Interest rate derivatives$(210) $
 $(210)$(97) $
 $(97)
Commodity derivatives:          
Natural Gas:          
Basis Swaps IFERC/NYMEX(22) (22) 
(89) (89) 
Swing Swaps IFERC(3) (1) (2)(1) 
 (1)
Fixed Swaps/Futures(22) (22) 
(26) (26) 
Forward Physical Swaps(1) 
 (1)
Forward Physical Contracts(7) 
 (7)
Power:          
Forwards(9) 
 (9)(30) 
 (30)
Futures(1) (1) 
(1) (1) 
Natural Gas Liquids – Forwards/Swaps(261) (261) 
NGLs – Forwards/Swaps(521) (521) 
Refined Products – Futures(2) (2) 
(5) (5) 
Crude – Futures(1) (1) 
Crude – Forwards/Swaps(190) (190) 
Total commodity derivatives(322) (310) (12)(870) (832) (38)
Total liabilities$(532) $(310) $(222)$(967) $(832) $(135)


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   Fair Value Measurements at
December 31, 2016
 Fair Value Total Level 1 Level 2 Level 3
Assets:       
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX$14
 $14
 $
 $
Swing Swaps IFERC2
 
 2
 
Fixed Swaps/Futures96
 96
 
 
Forward Physical Swaps1
 
 1
 
Power:

      
Forwards4
 
 4
 
Futures1
 1
 
 
Options – Calls1
 1
 
 
Natural Gas Liquids – Forwards/Swaps233
 233
 
 
Refined Products – Futures1
 1
 
 
Crude – Futures9
 9
 
 
Total commodity derivatives362
 355
 7
 
Total assets$362
 $355
 $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(17) (17) 
 
Crude – Futures(13) (13) 
 
Total commodity derivatives(472) (464) (8) 
Total liabilities$(666) $(464) $(201) $(1)
6.NET INCOME (LOSS) PER LIMITED PARTNER UNIT
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
Net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to the General Partner, the holder of the IDRs pursuant to the Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.


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A reconciliation of net income (loss) and weighted average units used in computing basic and diluted net income (loss) per unit is as follows:
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016
Net income$761
 $138
 $1,417
 $986
Less: Income attributable to noncontrolling interest110
 64
 243
 231
Net income, net of noncontrolling interest651
 74
 1,174
 755
General Partner’s interest in net income270
 220
 727
 740
Class H Unitholder’s interest in net income
 93
 98
 257
Class I Unitholder’s interest in net income
 2
 
 6
Common Unitholders’ interest in net income (loss)381
 (241) 349
 (248)
Additional (earnings) distributions allocated to General Partner
 (3) 12
 (9)
Distributions on employee unit awards, net of allocation to General Partner(6) (5) (19) (15)
Net income (loss) available to Common Unitholders$375
 $(249) $342
 $(272)
Weighted average Common Units – basic (1)
1,125.2
 761.1
 990.9
 749.7
Basic net income (loss) per Common Unit$0.33
 $(0.33) $0.35
 $(0.36)
        
Dilutive effect of unvested employee unit awards3.7
 
 4.6
 
Weighted average Common Units – diluted (1)
1,128.9
 761.1
 995.5
 749.7
Diluted net income (loss) per Common Unit$0.33
 $(0.33) $0.34
 $(0.36)
(1)    Excludes Common Units owned by the Partnership’s consolidated subsidiaries.
For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.
   Fair Value Measurements at
December 31, 2017
 Fair Value Total Level 1 Level 2
Assets:     
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX$11
 $11
 $
Swing Swaps IFERC13
 
 13
Fixed Swaps/Futures70
 70
 
Forward Physical Contracts8
 
 8
Power – Forwards23
 
 23
NGLs – Forwards/Swaps191
 191
 
Crude:     
Forwards/Swaps2
 2
 
Futures2
 2
 
Total commodity derivatives320
 276
 44
Other non-current assets21
 14
 7
Total assets$341
 $290
 $51
Liabilities:     
Interest rate derivatives$(219) $
 $(219)
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX(24) (24) 
Swing Swaps IFERC(15) (1) (14)
Fixed Swaps/Futures(57) (57) 
Forward Physical Contracts(2) 
 (2)
Power – Forwards(22) 
 (22)
NGLs – Forwards/Swaps(186) (186) 
Refined Products – Futures(25) (25) 
Crude:     
Forwards/Swaps(6) (6) 
Futures(1) (1) 
Total commodity derivatives(338) (300) (38)
Total liabilities$(557) $(300) $(257)
7.DEBT OBLIGATIONS
ETP Senior Notes Offering and Redemption
In October 2017,June 2018, ETP issued the Partnership redeemed all of the outstanding $500following senior notes:
$500 million aggregate principal amount of ETLP’s 6.50%4.20% senior notes due July 2021 and all2023;
$1.00 billion aggregate principal amount of the outstanding $7004.95% senior notes due 2028;
$500 million aggregate principal amount of ETLP’s 5.50%5.80% 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 2038; and
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$1.00 billion aggregate principal amount of 5.40%6.00% 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.2048.
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 principal is payable upon maturity. Interest on the senior notes is payable upon maturity and interest is paid semi-annually.


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The senior notes are guaranteed by the parent company (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 the Partnership’sETP’s existing and future senior debt, and senior in right of payment to any future subordinated debt the PartnershipETP 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 $2.96 billion net proceeds from the offering were used to repay borrowings outstanding under ETP’s revolving credit facility, for general partnership purposes and to redeem all of the following senior notes:

ETP’s $650 million aggregate principal amount of 2.50% senior notes due June 15, 2018;
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TablePanhandle’s $400 million aggregate principal amount of Contents
7.00% senior notes due June 15, 2018; and

ETP’s $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018.
The aggregate amount paid to redeem these notes was approximately $1.65 billion.
Credit Facilities and Commercial Paper
ETLPETP 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 unsecuredETP’s revolving credit facility (the “Sunoco Logistics“ETP Five-Year Credit Facility”), which matures previously allowed for unsecured borrowings up to $4.00 billion and matured in March 2020.December 2022. On October 19, 2018, the ETP Five-Year Credit Facility was amended to increase the borrowing capacity by $1.00 billion, to $5.00 billion, and to extend the maturity date to December 1, 2023. The Sunoco LogisticsETP 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 September 30, 2017,2018, the Sunoco LogisticsETP Five-Year Credit Facility had $35$1.78 billion outstanding, of which $1.57 billion was commercial paper. The amount available for future borrowings was $2.06 billion after taking into account letters of credit of $163 million, but before taking into account the additional capacity from the October 19, 2018 amendment. The weighted average interest rate on the total amount outstanding as of outstanding borrowings.September 30, 2018 was 3.00%.
ETP 364-Day Facility
In December 2016, Sunoco Logistics entered into an agreement for aETP’s 364-day maturityrevolving credit facility (“(the “ETP 364-Day Credit Facility”), due previously allowed for unsecured borrowings up to mature$1.00 billion and matured on November 30, 2018. On October 19, 2018, 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, theETP 364-Day Credit Facility was terminated and repaid in May 2017.amended to extend the maturity date to November 29, 2019. As of September 30, 2018, the ETP 364-Day Facility had no outstanding borrowings.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco LogisticsETP and Phillips 66 completed project-level financing of the Bakken Pipeline.pipeline. The $2.50 billion credit facility provides substantially all of the remaining capital necessary to complete the projects.matures in August 2019 (the “Bakken Credit Facility”). As of September 30, 2017,2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings, all of which has been reflected in current maturities of long-term debt on the Partnership’s consolidated balance sheet. The weighted average interest rate on the total amount outstanding as of September 30, 2018 was outstanding under this credit facility.
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”)3.85%. In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.
Compliance with Our Covenants
We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, 2017.2018.


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8.PREFERRED UNITS
In January 2017, Energy Transfer Partners, L.P. repurchased all of its 1.9 million outstanding Preferred Units for cash in the aggregate amount of $53 million.
9.EQUITY
The changes in outstanding common units during the nine months ended September 30, 20172018 were as follows:
  Number of Units
Number of common units at December 31, 2016  (1)
2017
 794.8
Common Units issued in connection with public offerings54.0
Common units issued in connection with equity distribution agreements22.61,164.1
Common units issued in connection with the distribution reinvestment plan 4.62.9
Common units issued to ETE in a private placement transactionconnection with certain transactions 23.7
Common unit increase from Sunoco Logistics Merger (2)
255.41.3
Issuance of common units under equity incentive plans 0.40.1
Repurchases of common units in open-market transactions(1.2)
Number of common units at September 30, 20172018 1,155.51,167.2
(1)
The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange
Subsequent to the ETE-ETP Merger in October 2018, all of the outstanding ETP common units are held directly or indirectly by ETE, including the ETP common units issued in connection with the Sunoco Logistics Merger.


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(2)
Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.
In connection with the Sunoco Logistics Merger,conversion of the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated.general partner interest to a non-economic interest and the cancellation of the IDRs, as discussed in Note 1, and the contributions of the investments in ETE’s other subsidiaries, as discussed in Note 2. In May 2017,addition, the Partnership entered into an equity distribution agreementETP Class I units and Class J units were also cancelled in connection with an aggregate offering price up to $1.00 billion. the ETE-ETP Merger.
Equity Distribution Program
During the nine months ended September 30, 2017,2018, there were no units issued under the Partnership received proceeds of $498 million, net of $5 million of commissions, from the issuance of common units pursuant toPartnership’s equity distribution agreements, which were used for general partnership purposes.
agreement. In connection with the Sunoco LogisticsETE-ETP Merger, the previous Energy Transfer Partners, L.P.equity distribution reinvestment planprogram was terminated. In July 2017, the Partnership initiated a new distribution reinvestment plan. terminated in October 2018.
Distribution Reinvestment Program
During the nine months ended September 30, 2017,2018, distributions of $106$57 million were reinvested under the Partnership’s distribution reinvestment plan. In connection with the ETE-ETP Merger, the distribution reinvestment program was terminated in October 2018.
AugustPreferred Units
ETP issued 950,000 Series A Preferred Units and 550,000 Series B Preferred Units in November 2017 Units Offering
In August 2017, the Partnershipand has issued 54 million ETP commonadditional preferred units in an underwritten public offering. Net2018, as discussed below. Subsequent to the ETE-ETP Merger, all of ETP’s Series A, Series B, Series C and Series D Preferred Units remain outstanding.
Series C Preferred Units Issuance
In April 2018, ETP issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $997 million from the offering$450 million. The proceeds were used by the Partnership to repay amounts outstanding under itsETP’s revolving credit facilities, to fund capital expendituresfacility and for general partnership purposes.
Distributions on the Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The Series C Preferred Units are redeemable at ETP’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Bakken Equity SaleSeries D Preferred Units Issuance
In February 2017, Bakken Holdings Company LLC, an entity in which the Partnership 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, the Partnership contributed a portion2018, ETP issued 17.8 million of its ownership interest7.625% Series D Preferred Units at a price of $25 per unit, resulting in Dakota Accesstotal gross proceeds of $445 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and ETCOfor general partnership purposes.
Distributions on the Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, PEP,but excluding, August 15, 2023, at 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 allrate of 7.625% 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 August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.
Quarterly Distributions of Available Cash
Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the Partnership’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreement prior$25 liquidation preference equal to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the endan annual floating rate of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement.three-month LIBOR, determined quarterly, plus a spread of 4.378% per annum. The general partner has broad discretion to establish cash reserves that it determinesSeries D Preferred Units are necessaryredeemable at ETP’s option on or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishmentAugust 15, 2023 at a redemption price of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833$25 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.Series D


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The following table showsPreferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the target distribution levelsdate of redemption.
Cash Distributions
Distributions on common units declared and distribution “splits” betweenpaid by the general partner andPartnership subsequent to December 31, 2017 but prior to the holdersclosing of the Partnership’s common units:ETE-ETP Merger as discussed in Note 1 were as follows:
    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%
Quarter Ended Record Date Payment Date Rate
December 31, 2017 February 8, 2018 February 14, 2018 $0.5650
March 31, 2018 May 7, 2018 May 15, 2018 0.5650
June 30, 2018 August 6, 2018 August 14, 2018 0.5650
(1) Includes general partner and limited partner interests, basedDistributions 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 distributionsETP’s preferred units declared and/or paid by the Partnership subsequent to the Sunoco Logistics Merger:December 31, 2017 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
ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods.
  Total Year
2017 (remainder) $173
2018 153
2019 128
Each year beyond 2019 33
Period Ended Record Date Payment Date Rate
Series A Preferred Units      
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
June 30, 2018 August 1, 2018 August 15, 2018 31.250
Series B Preferred Units      
December 31, 2017 February 1, 2018 February 15, 2018 $16.378
June 30, 2018 August 1, 2018 August 15, 2018 33.125
Series C Preferred Units      
June 30, 2018 August 1, 2018 August 15, 2018 $0.5634
September 30, 2018 November 1, 2018 November 15, 2018 0.4609
Series D Preferred Units      
September 30, 2018 November 1, 2018 November 15, 2018 $0.5931
Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
Available-for-sale securities(1)$7
 $2
$6
 $8
Foreign currency translation adjustment(5) (5)(5) (5)
Actuarial gain related to pensions and other postretirement benefits9
 7
Actuarial loss related to pensions and other postretirement benefits(7) (5)
Investments in unconsolidated affiliates, net3
 4
14
 5
Total AOCI, net of tax$14
 $8
$8
 $3
(1)
Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale securities to common unitholders.
10.9.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 incrementalstatutory rate primarily due to partnership earnings that are not subject to United States federal and most state income tax expense of approximately $68 million duringtaxes at the period. In addition, forpartnership level. For the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. The three and nine months ended September 30, 2017 also reflect increased2018, the Partnership’s income tax expense due to higher earnings amongbenefit also reflected $109 million and $179 million, respectively, of deferred benefit adjustments as the Partnership’s consolidated corporate subsidiaries. Forresult of a state statutory rate reduction.
Sunoco, Inc. historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the three and nine months ended SeptemberInternal


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30,Revenue Service (“IRS”) excluding these government incentive payments from federal taxable income. The IRS denied the amended returns and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) on this issue.  In November 2016, the Partnership’s income tax benefit primarily resulted from losses amongCFC ruled against Sunoco, Inc., and the Partnership’s consolidated corporate subsidiaries.Federal Circuit affirmed the CFC’s ruling on November 1, 2018.  Sunoco, Inc. is considering seeking further review of this decision.  Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims.
11.10.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
Contingent Residual Support Agreement – AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETLP (formerly Energy Transfer Partners, L.P.) agreed to provide contingent residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchasers. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETLP under the contingent residual support agreement. In February 2017, AmeriGas repurchased a portion of its 7.00% senior notes. The remaining outstanding 7.00% senior notes were repurchased in May 2017, and ETLP no longer provides contingent residual support for any AmeriGas notes.
Guarantee of Sunoco LP Notes
In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amountcertain of 6.375%Sunoco LP’s senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC. LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes, repaid and terminated the term loan and issued the following notes (the “Sunoco LP Notes”) for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
$1.00 billion aggregate principal amount of 4.875% senior notes due 2023;
$800 million aggregate principal amount of 5.50% senior notes due 2026; and
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.
In connection with the issuance of the Sunoco LP Notes, Sunoco LP entered into a registration rights agreement with the initial purchasers pursuant to which Sunoco LP agreed to complete an offer to exchange the Sunoco LP Notes for an issue of registered notes with terms substantively identical to each series of Sunoco LP Notes and evidencing the same indebtedness as the Sunoco LP Notes on or before January 23, 2019.
FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The FERC approved an audit is ongoing.  report in October 2018.  In response to the findings in the audit report, the Company expects to make certain changes to its processes, policies and procedures; however, the Company does not expect the findings to result in any changes to its financial statements.
Commitments
In the normal course of our business, we purchase, processETP 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 believeETP 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.
Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.


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We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. 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$29
 $19
 $68
 $58
Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2018 2017 2018 2017
Rental expense$21
 $29
 $60
 $68
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


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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.also intervened. The SRST filed an amended complaint and added claims based on treaties between the tribesSRST and the 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 presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016,The CRST moved for a preliminary injunction and TROtemporary restraining order (“TRO”) to block operation of the pipeline. These motionspipeline, which 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.
The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala 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. TheOn May 3, 2018, the District Court ordered briefingthe USACE to determine whetherfile a status report by June 8, 2018 informing the pipeline should remain in operation duringCourt when the pendency ofUSACE expects the USACE’s reviewremand process or whether to vacatebe complete. On June 8, 2018, the existing permits.USACE filed a status report stating that they will conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they will 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. The USACE and Dakota Access opposed any shutdownindicated that a document detailing its remand analysis would be filed after a “confidentiality review.” Following the submission by USACE of operationsits detailed remand analysis, it is expected that the Court will make a determination regarding the three discrete issues covered by the remand order.


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On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during thisthe remand process. First, Dakota Access must retain an independent third-party to review process. On October 11,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 has 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 has 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.
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 issuedin 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 March 19, 2018, the District 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 concluded that YST’s NHPA claims are moot because construction of the pipeline is complete and that the government’s review process did not violate NEPA or the various treaties cited by the YST.
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 seek an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advisedfrom the Court thatdirecting the USACE as to how it expects to complete thisshould conduct its additional work byreview on remand. Dakota Access pipeline and the USACE opposed both motions. On April 2018. The16, 2018, the Court has stayed consideration of any other claims until it fully resolves the remaining issues relating to its remand order.denied both motions.
While we believeETP believes that the pending lawsuits are unlikely to blockhalt or suspend operation of the pipeline, we cannot assure this outcome. WeETP cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.


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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 or will be seeking reimbursement for these losses.
MTBE Litigation
Sunoco, Inc. and/or Sunoco, Inc. (R&M) (now known as Sunoco (R&M), along with other refiners, manufacturers and sellers of gasoline,LLC) 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 September 30, 2017,2018, Sunoco, Inc. is a defendant in six cases, including casesone case each initiated by the States of New Jersey,Maryland, Vermont Pennsylvania,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. TheMaryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P.
In late July 2018, the Court in the Vermont matter denied Plaintiff’s motion to amend its complaint to add specific allegations regarding some of the sites the court approvedpreviously dismissed. In early September 2018, Sunoco, Inc. participated in a defense group effort to resolve the Judicial Consent Order on October 10, 2017.case without further litigation. A settlement in principle to resolve the remaining statewide Vermont Case was reached in September 2018.
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,


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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-ETP 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; Regency GP LLC; ETE, ETP, 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. 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 hearing on theseOn 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. Trial is currently set for January 9, 2018.September 23-27, 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 ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise approximately $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and


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pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP intends to file aOn June 8, 2018, the Texas Supreme Court ordered briefing on the merits. ETP’s petition for review withremains under consideration by the Texas Supreme Court.
Sunoco LogisticsETE-ETP Merger Litigation
SevenOn September 17, 2018, William D. Warner (“Plaintiff”), a purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separatelyETP unitholder, filed sevena putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the membersasserting violations of various provisions of the ETP Board,Securities Exchange Act of 1934 and ETE (the “ETP-SXL Defendants”)various rules promulgated thereunder in connection with the announcementETE-ETP Merger against ETP, Kelcy L. Warren, Michael K. Grimm, Marshall S. McCrea, Matthew S. Ramsey, David K. Skidmore, and W. Brett Smith (“Defendants”). Plaintiff specifically alleges that the Form S-4 Registration Statement issued in connection with the ETE-ETP Merger omits and/or misrepresents material information. Defendants believe the allegations have no merit and intend to defend vigorously against them. On October 26, 2018, Plaintiff and Defendants entered into a stipulation staying Defendants’ response deadlines until the designation of a lead plaintiff/lead counsel structure in accordance with 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,Private Securities Litigation Reform Act.
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 Delaware (the “Sunoco Logistics Merger Litigation”). The ETP UnitholderLouisiana. Plaintiffs allege causesthat the USACE’s issuance of action challengingpermits authorizing the mergerconstruction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the proxy statement/prospectus filed in connection withRivers and Harbors Act. They asked the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs seek rescissiondistrict court to vacate these permits and to enjoin construction of the Sunoco Logistics Merger or rescissory damagesproject through the Basin until the USACE corrects alleged deficiencies in its decision-making process. ETP, 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.


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On January 29, 2018, Plaintiffs filed motions for ETP unitholders,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 well asmoot. 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 award“as applied” challenge to the USACE’s application of costs and attorneys’ fees.the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 11, 2018. On September 11, 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.
At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiff’s original complaint, which it has done. Summary judgment briefing will be concluded by the Spring of 2019.
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.
Litigation filed by BP Products
On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.
SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.Rover
On May 26,November 3, 2017, the Administrative Law Judge Patricia E. HurtState of Ohio and the Ohio Environmental Protection Agency (“ALJ”Ohio EPA”) issued her initial decisionfiled suit against Rover and Pretec Directional Drilling, LLC (“Initial Decision”Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and found that SPLP had acted discriminatorily by entering into T&D agreementscertain 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 the two shippers other than BPRover and recommendedPretec, “Defendants”) were added as defendants on April 17, 2018 and July 18, 2018.
Ohio EPA alleges that the FERC (1) adoptDefendants 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.
In January 2018, Ohio EPA sent a letter to the FERC Trial Staff’s $13 million alternative damages proposal, (2) voidto express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume historyRover Pipeline construction. Rover sent a January 24 response to the level prior to the effective date of the proration policy,FERC and (4) investigate the proration policy. The ALJ heldstated, among other things, that BP’s claim for damagesas Ohio EPA conceded, Rover was not time-barredconducting its drilling operations in its entirety, butaccordance with specified procedures that it was not entitled to damages more than two years prior to the filing of the complaint.
On July 26, 2017, each of the parties filed withhad 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 brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.fact with which Ohio EPA concurs.
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 September 30, 20172018 and December 31, 2016,2017, accruals of approximately $66$55 million and $77$53 million, respectively, were reflected on our consolidated balance sheets related to these


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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.


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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,On April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against Sunoco Logistics received multiple Notice of ViolationsPipeline L.P. (“NOVs”SPLP”) frombefore the Delaware County Regional Water Quality Control AuthorityPennsylvania Public Utility Commission (“DELCORA”PUC”). Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“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 homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increases the risk of damage to the 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 an order (i) prohibiting construction of ME2 and ME2x in the Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (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 release to the public 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 operation of ME1 and suspend further construction of ME2 and ME2x in the Township.
Following a discharge at its Marcus Hook Industrial Complexhearing on May 7, 2018 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“MHIC”ALJ”) issued an Order on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to shut 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 the Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the PUC, 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 2016. Sunoco Logistics2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also entered in a Consent Order and Agreement fromrequired to provide an affidavit that the Pennsylvania Department of Environmental Protection (“PADEP”) related to its tank inspection plan at MHIC.  These actions propose penalties in excess of $0.1 million, and ETP is currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.
The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred duringissued appropriate approvals for construction of ME2 and ME2x in the Rover pipeline project. The alleged violations include inadvertent returnsTownship before recommencing construction of drilling mudsME2 and fluids at horizontal directional drilling (“HDD”)ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 2, 2018 the PUC entered an Order lifting the stay of construction on ME2 and ME2x in Ohio that affected watersthe Township with respect to four of the State, storm water control violations, improper disposaleight areas within the Township where the necessary environmental permits had been issued. Subsequently, after PADEP’s issuance of spent drilling mud containing diesel fuel residuals,permit modifications for two of the four remaining construction 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 the action. SPLP submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and open burning. The alleged violations occurred from April to July, 2017. The Ohio EPA has proposed penalties of approximately $2.3 million in connection withintervenors opposed that petition. On September 27, 2018, the alleged violations and is seeking certain corrective actions. ETP is working with Ohio EPA to resolve the matter. The timing or outcome of this matter cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERCCommonwealth Court issued an independent third party assessmentOrder that certified for appeal the issue 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 suggestionsSenator Dinniman’s standing. The Order stays all proceedings in the assessment and to implement additional voluntary protocols. On September 18, 2017, the FERC authorized Rover to resume HDD activities at the Tuscarawas River site and nine other river crossing sites. On October 20, 2017, the FERC authorized Rover to resume HDD activities at two additional sites.
On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover, among other things, to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover had 20 days to submit a corrective action plan and schedule for agency review. The order followed several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order and has already addressed many of the stormwater control issues. On August 9, 2017, WVDEP lifted the Cease and Desist requirement.PUC.
On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project.  On August 1, 2017 the EHB lifted the order as to two drill locations.  On August 3, 2017, 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”).PADEP.  The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting.  On August 7, 2017 a final settlement was reached.  A stipulated order has been submitted to the EHB Judge with respect to the settlement.  The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation.  Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits.  Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company. On July 31, 2018 the underlying permit appeals in which the above settlements occurred were withdrawn in a settlement between the appellants and PADEP. That settlement did not involve SPLP.


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In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project.  Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval.  SPLP is working to fulfillhas fulfilled the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.
No amounts have been recorded in our September 30, 20172018 or December 31, 20162017 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.


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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 and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”)SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP 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-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July 2017, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality (“LDEQ”) during which the agencies presented their initial demand for civil penalties and injunctive relief. In short,Since then, the parties have reached an agreement in principal to resolve all penalties with DOJ and EPA proposed federal penalties totaling $7 million for the three releasesLDEQ along with a demand for injunctive relief requirements to be completed within three years all of which is being formalized in a Consent Decree. In addition to resolution of the civil penalty, we continue to discuss national 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 Louisiana Department2X pipelines be stopped.  The Administrative Order detailed alleged violations of Environmental Quality proposed a state penaltythe permits issued by PADEP in February 2017, during the construction of approximately $1 millionthe project.  SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joinedcompliance issues.  Those compliance issues could not be fully resolved by the penalty discussions at this point. We are currently workingdeadline 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 counteroffergoing forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to pay a $12.6 million civil penalty to the Louisiana DepartmentCommonwealth of Pennsylvania.  In the 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 adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. SPLP concurrently filed a request to the Pennsylvania Environmental Quality.Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.


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Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
Certaincertain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs.polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
Certaincertain 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.
Legacylegacy 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, 2017,2018, Sunoco, Inc. had been named as a PRP at approximately 4441 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.


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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.
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
Current$36
 $26
$36
 $36
Non-current276
 283
281
 314
Total environmental liabilities$312
 $309
$317
 $350
In 2013, we 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 September 30, 2018 and 2017, and 2016, Sunoco, Inc.the Partnership recorded $4$17 million and $10$5 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2018 and 2017, and 2016, Sunoco, Inc.the Partnership recorded $14$28 million and $24$18 million, 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 Pipeline Hazardous Materials Safety Administration (“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.


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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 Health and Safety Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
11.REVENUE
The following disclosures discuss the Partnership’s revised revenue recognition policies upon the adoption of ASU 2014-09 on January 1, 2018, as discussed in Note 1. These policies were applied to the current period only, and the amounts reflected in the Partnership’s consolidated financial statements for the three and nine months ended September 30, 2017 were recorded under the Partnership’s previous accounting policies.
Disaggregation of revenue
The Partnership’s consolidated financial statements reflect the following six reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes:
intrastate transportation and storage;
interstate transportation and storage;
midstream;
NGL and refined products transportation and services;
crude oil transportation and services; and
all other.
Note 14 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.
Intrastate transportation and storage revenue
Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.
Interstate transportation and storage revenue
Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible.


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Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.
Midstream revenue
Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream segment enters into include:
Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed.
Keepwhole: Contracts under which we gather raw natural gas from a third party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed.
Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:
In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.
Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.
Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.
Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer,


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deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for 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.
NGL and refined products transportation and services revenue
Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.
Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606.
Crude oil transportation and services revenue
Our crude oil transportation and service segment are primarily derived from provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed.
Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.


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Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606.
All other revenue
Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard.
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. As of September 30, 2018 and January 1, 2018, no contract assets have been recognized.
The Partnership recognizes a contract liability if the customer's payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. As of September 30, 2018, the Partnership had $349 million in deferred revenues representing the current value of our future performance obligations.
The amount of revenue recognized for the three and nine months ended September 30, 2018 that was included in the deferred revenue liability balance as of January 1, 2018 was $12 million and $75 million, respectively.
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 contract consideration it expects to be entitled to, 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 September 30, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $40.13 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:
  Years Ending December 31,    
  2018 (remainder) 2019 2020 Thereafter Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2018 $1,426
 $5,066
 $4,568
 $29,069
 $40,129


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Practical Expedients Utilized by the Partnership
The Partnership elected the following practical expedients in accordance with Topic 606:
Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.
Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.
Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.
12.DERIVATIVE ASSETS AND LIABILITIES
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we 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


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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 our intrastate transportation and storage segment and operational gas sales on 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 our midstream segment whereby our 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 our 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 financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our 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 our 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 our 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.


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The following table details our outstanding commodity-related derivatives:
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
Notional Volume Maturity Notional Volume MaturityNotional Volume Maturity Notional Volume Maturity
Mark-to-Market Derivatives        
(Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Fixed Swaps/Futures1,297,500
 2017-2018 (682,500) 2017358
 2018-2019 1,078
 2018
Basis Swaps IFERC/NYMEX(1)
(15,810,000) 2017-2019 2,242,500
 201769,685
 2018-2020 48,510
 2018-2020
Options – Puts13,000,000
 2018 
 (17,273) 2019 13,000
 2018
Power (Megawatt):        
Forwards665,040
 2017-2018 391,880
 2017-2018429,720
 2018-2019 435,960
 2018-2019
Futures(213,840) 2017-2018 109,564
 2017-2018309,123
 2018-2019 (25,760) 2018
Options – Puts(280,800) 2017-2018 (50,400) 2017157,435
 2018-2019 (153,600) 2018
Options – Calls545,600
 2017-2018 186,400
 2017321,240
 2018-2019 137,600
 2018
Crude (Bbls) – Futures(160,000) 2017 (617,000) 2017
(Non-Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Basis Swaps IFERC/NYMEX67,500
 2017-2020 10,750,000
 2017-2018(7,705) 2018-2021 4,650
 2018-2020
Swing Swaps IFERC91,897,500
 2017-2019 (5,662,500) 201769,145
 2018-2019 87,253
 2018-2019
Fixed Swaps/Futures(20,220,000) 2017-2019 (52,652,500) 2017-2019(1,784) 2018-2020 (4,700) 2018-2019
Forward Physical Contracts(140,937,993) 2017-2018 (22,492,489) 2017(54,151) 2018-2020 (145,105) 2018-2020
Natural Gas Liquid (Bbls) – Forwards/Swaps(8,747,200) 2017-2019 (5,786,627) 2017
Refined Products (Bbls) – Futures(701,000) 2017 (2,240,000) 2017
NGL (MBbls) – Forwards/Swaps(4,997) 2018-2019 (2,493) 2018-2019
Crude (MBbls) – Forwards/Swaps35,280
 2018-2019 9,172
 2018-2019
Refined Products (MBbls) – Futures(1,521) 2018-2019 (3,783) 2018-2019
Fair Value Hedging Derivatives        
(Non-Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Basis Swaps IFERC/NYMEX(41,102,500) 2017 (36,370,000) 2017(21,475) 2018-2019 (39,770) 2018
Fixed Swaps/Futures(41,102,500) 2017 (36,370,000) 2017(21,475) 2018-2019 (39,770) 2018
Hedged Item – Inventory41,102,500
 2017 36,370,000
 201721,475
 2018-2019 39,770
 2018
(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.


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The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
Term 
Type(1)
 Notional Amount Outstanding 
Type(1)
 Notional Amount Outstanding
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
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
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate $
 $300
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
 Forward-starting to pay a fixed rate of 3.56% and receive a floating rate 400
 300
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
July 2021(2)
 Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400
 
December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
(1) 
Floating rates are based on 3-month LIBOR.  
(2) 
Represents the effective date. These forward-starting swaps have terms 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 the Partnership’s 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, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our 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.
The Partnership has 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 us on or about the settlement date for non-exchange traded derivatives, and we 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.


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Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
 Fair Value of Derivative Instruments Fair Value of Derivative Instruments
 Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives
 September 30, 2017 December 31, 2016 September 30, 2017 December 31, 2016 September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017
Derivatives designated as hedging instruments:                
Commodity derivatives (margin deposits) $7
 $
 $
 $(4) $
 $14
 $(6) $(2)
Derivatives not designated as hedging instruments:                
Commodity derivatives (margin deposits) 222
 338
 (262) (416) 477
 262
 (537) (281)
Commodity derivatives 50
 24
 (60) (52) 122
 44
 (327) (55)
Interest rate derivatives 
 
 (210) (193) 
 
 (97) (219)
Embedded derivatives in Preferred Units 
 
 
 (1)
 272
 362
 (532) (662) 599
 306
 (961) (555)
Total derivatives $279
 $362
 $(532) $(666) $599
 $320
 $(967) $(557)
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 September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017
Derivatives without offsetting agreements Derivative assets (liabilities) $
 $
 $(210) $(194) Derivative liabilities $
 $
 $(97) $(219)
Derivatives in offsetting agreements:Derivatives in offsetting agreements:        Derivatives in offsetting agreements:        
OTC contracts Derivative assets (liabilities) 50
 24
 (60) (52) Derivative assets (liabilities) 122
 44
 (327) (55)
Broker cleared derivative contracts Other current assets 229
 338
 (262) (420) Other current assets (liabilities) 477
 276
 (543) (283)
Total gross derivativesTotal gross derivatives 279
 362
 (532) (666)Total gross derivatives 599
 320
 (967) (557)
Offsetting agreements:Offsetting agreements:        Offsetting agreements:        
Counterparty netting Derivative assets (liabilities) (10) (4) 10
 4
 Derivative assets (liabilities) (29) (20) 29
 20
Payments on margin deposit Other current assets (220) (338) 220
 338
Counterparty netting Other current assets (liabilities) (477) (263) 477
 263
Total net derivativesTotal net derivatives $49
 $20
 $(302) $(324)Total net derivatives $93
 $37
 $(461) $(274)
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-term depending on the anticipated settlement date.


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The following tables summarize the amounts recognized in income with respect to our derivative financial instruments:
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 EffectivenessLocation 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
September 30,
 Nine Months Ended
September 30,
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016 2018 2017 2018 2017
Derivatives in fair value hedging relationships (including hedged item):                
Commodity derivativesCost of products sold $2
 $(9) $4
 $8
Cost of products sold $
 $2
 $9
 $4
Total $2
 $(9) $4
 $8
Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on DerivativesLocation 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,
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016 2018 2017 2018 2017
Derivatives not designated as hedging instruments:                
Commodity derivatives – TradingCost of products sold $(5) $(8) $21
 $(24)Cost of products sold $3
 $(5) $36
 $21
Commodity derivatives – Non-tradingCost of products sold (12) (14) (15) (57)Cost of products sold 21
 (12) (352) (15)
Interest rate derivativesLosses on interest rate derivatives (8) (28) (28) (179)Gains (losses) on interest rate derivatives 45
 (8) 117
 (28)
Embedded derivativesOther, net 
 8
 1
 4
Other, net 
 
 
 1
Total $(25) $(42) $(21) $(256) $69
 $(25) $(199) $(21)
13.RELATED PARTY TRANSACTIONS
In June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 9.
We previously had agreements with ETE to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries. These agreements expired in 2016.
The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.
The following table summarizes the affiliate revenues on our consolidated statements of operations:
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016
Affiliated revenues$190
 $63
 $441
 $270
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2018 2017 2018 2017
Affiliated revenues$192
 $190
 $700
 $441


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The following table summarizes the related company balances on our consolidated balance sheets:
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
Accounts receivable from related companies:      
ETE$
 $22
$42
 $
FGT15
 11
Phillips 6630
 20
Sunoco LP204
 96
207
 219
FGT15
 15
Trans-Pecos Pipeline, LLC10
 1
Other116
 76
29
 67
Total accounts receivable from related companies:$335
 $209
$333
 $318
      
Accounts payable to related companies:      
Sunoco LP$178
 $20
$178
 $195
USAC45
 
Other26
 23
64
 14
Total accounts payable to related companies:$204
 $43
$287
 $209
 September 30, 2017 December 31, 2016
Long-term notes receivable (payable) – related companies:   
Sunoco LP$85
 $87
Phillips 66
 (250)
Net long-term notes receivable (payable) – related companies$85
 $(163)
 September 30, 2018 December 31, 2017
Long-term notes receivable from related company:   
Sunoco LP$85
 $85
14.REPORTABLE SEGMENTS
Subsequent to the Sunoco Logistics Merger, ourOur consolidated financial statements reflect the following reportable segments, which conduct their business in the United States, as follows:
intrastate transportation and storage;
interstate transportation and storage;
midstream;
NGL and refined products transportation and services;
crude oil transportation and services; and
all other.
The amounts included in the NGL and refined products transportation and services segment and the crude oil transportation and services segment have been retrospectively adjusted in these consolidated financial statements as a result of the Sunoco Logistics Merger.
The Partnership previously presented its retail marketing business as a separate reportable segment. Due to the transfer of the general partner interest of Sunoco LP from Energy Transfer Partners, L.P. to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from Energy Transfer Partners, L.P. to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP owned by the Partnership. As of September 30, 2017, the Partnership owned 43.5 million Sunoco LP common units, representing 43.7% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented.
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, refined product sales and gathering, transportation and other fees. Revenues from our crude


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oil transportation and services segment are primarily reflected in crude sales. Revenues from our all other segment are primarily reflected in other.
We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include


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unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments).adjustments. Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’sPartnership's proportionate ownership.
The following tables present financial information by segment:
Three Months Ended
September 30,
 Nine Months Ended
September 30,
Three Months Ended
September 30,
 Nine Months Ended
September 30,
2017 2016 2017 20162018 2017 2018 2017
Revenues:              
Intrastate transportation and storage:              
Revenues from external customers$729
 $583
 $2,196
 $1,457
$846
 $729
 $2,424
 $2,196
Intersegment revenues44
 175
 146
 400
76
 44
 186
 146
773
 758
 2,342
 1,857
922
 773
 2,610
 2,342
Interstate transportation and storage:              
Revenues from external customers220
 231
 652
 714
390
 220
 1,026
 652
Intersegment revenues4
 5
 14
 15
5
 4
 13
 14
224
 236
 666
 729
395
 224
 1,039
 666
Midstream:              
Revenues from external customers665
 582
 1,863
 1,799
537
 665
 1,571
 1,863
Intersegment revenues1,100
 761
 3,154
 1,966
1,716
 1,100
 4,170
 3,154
1,765
 1,343
 5,017
 3,765
2,253
 1,765
 5,741
 5,017
NGL and refined products transportation and services:              
Revenues from external customers1,989
 1,397
 5,874
 4,014
2,948
 1,989
 7,878
 5,874
Intersegment revenues81
 148
 241
 315
115
 81
 299
 241
2,070
 1,545
 6,115
 4,329
3,063
 2,070
 8,177
 6,115
Crude oil transportation and services:              
Revenues from external customers2,714
 1,856
 7,749
 5,146
4,422
 2,714
 12,942
 7,749
Intersegment revenues11
 
 16
 
16
 11
 44
 16
2,725
 1,856
 7,765
 5,146
4,438
 2,725
 12,986
 7,765
All other:              
Revenues from external customers656
 882
 2,110
 2,171
498
 656
 1,490
 2,110
Intersegment revenues27
 74
 139
 350
27
 27
 108
 139
683
 956
 2,249
 2,521
525
 683
 1,598
 2,249
Eliminations(1,267) (1,163) (3,710) (3,046)(1,955) (1,267) (4,820) (3,710)
Total revenues$6,973
 $5,531
 $20,444
 $15,301
$9,641
 $6,973
 $27,331
 $20,444


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Three Months Ended
September 30,
 Nine Months Ended
September 30,
Three Months Ended
September 30,
 Nine Months Ended
September 30,
2017 2016 2017 20162018 2017* 2018 2017*
Segment Adjusted EBITDA:              
Intrastate transportation and storage$163
 $133
 $480
 $461
$221
 $163
 $621
 $480
Interstate transportation and storage273
 278
 800
 848
416
 273
 1,069
 800
Midstream356
 314
 1,088
 875
434
 356
 1,225
 1,088
NGL and refined products transportation and services423
 383
 1,196
 1,072
498
 439
 1,410
 1,208
Crude oil transportation and services396
 169
 830
 521
682
 420
 1,694
 835
All other133
 113
 363
 395
78
 133
 242
 363
Total1,744
 1,390
 4,757
 4,172
2,329
 1,784
 6,261
 4,774
Depreciation, depletion and amortization(596) (503) (1,713) (1,469)(636) (596) (1,827) (1,713)
Interest expense, net(367) (345) (1,052) (981)(387) (352) (1,091) (1,020)
Losses on interest rate derivatives(8) (28) (28) (179)
Non-cash unit-based compensation expense(19) (22) (57) (60)
Gain on Sunoco LP common unit repurchase
 
 172
 
Loss on deconsolidation of CDM
 
 (86) 
Gains (losses) on interest rate derivatives45
 (8) 117
 (28)
Non-cash compensation expense(20) (19) (61) (57)
Unrealized gains (losses) on commodity risk management activities(81) (15) 17
 (96)97
 (81) (255) 17
Inventory valuation adjustments86
 37
 30
 143
Adjusted EBITDA related to unconsolidated affiliates(279) (240) (765) (711)(257) (279) (670) (765)
Equity in earnings of unconsolidated affiliates127
 65
 139
 260
113
 127
 147
 139
Impairment of investment in an unconsolidated affiliate
 (308) 
 (308)
Other, net42
 43
 111
 84
13
 27
 100
 79
Income before income tax expense (benefit)$649
 $74

$1,439

$855
Income before income tax (expense) benefit$1,297
 $603

$2,807

$1,426
* As adjusted. See Note 1.
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
Assets:      
Intrastate transportation and storage$5,179
 $5,164
$5,874
 $5,020
Interstate transportation and storage12,194
 10,833
14,143
 13,518
Midstream19,781
 17,873
20,175
 20,004
NGL and refined products transportation and services16,445
 14,128
18,438
 17,600
Crude oil transportation and services17,267
 15,941
17,458
 17,736
All other6,145
 6,252
3,068
 4,087
Total assets$77,011
 $70,191
$79,156
 $77,965
15.CONSOLIDATING GUARANTOR FINANCIAL INFORMATION
Prior to the Sunoco Logistics Merger, Sunoco Logistics Partners Operations L.P., a subsidiary of Sunoco Logistics wasETP, is the issuer of multiple series of senior notes that wereare guaranteed by Sunoco Logistics. Subsequent to the Sunoco Logistics Merger, these notes continue to be guaranteed by the parent company.
ETP. These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Partners,Operating, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”
The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting.


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To present the supplemental condensed consolidating financial information on a comparable basis, the prior period financial information has been recast as if the Sunoco Logistics Merger occurred on January 1, 2016.
The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows:
September 30, 2017September 30, 2018
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated PartnershipParent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash and cash equivalents$
 $49
 $330
 $
 $379
$
 $
 $379
 $
 $379
All other current assets
 77
 5,324
 
 5,401
4
 56
 6,806
 (892) 5,974
Property, plant and equipment, net
 
 56,972
 
 56,972

 
 60,550
 
 60,550
Investments in unconsolidated affiliates25,174
 11,605
 4,221
 (36,779) 4,221
49,614
 12,435
 3,599
 (62,049) 3,599
All other assets
 25
 10,013
 
 10,038
8
 75
 8,571
 
 8,654
Total assets$25,174
 $11,756
 $76,860
 $(36,779) $77,011
$49,626
 $12,566
 $79,905
 $(62,941) $79,156
                  
Current liabilities$(1,494) $(3,819) $12,199
 $
 $6,886
$(1,118) $(3,407) $14,675
 $(892) $9,258
Non-current liabilities
 7,664
 31,604
 
 39,268
22,823
 7,605
 4,794
 
 35,222
Noncontrolling interest
 
 4,191
 
 4,191

 
 6,334
 
 6,334
Total partners’ capital26,668
 7,911
 28,866
 (36,779) 26,666
27,921
 8,368
 54,102
 (62,049) 28,342
Total liabilities and equity$25,174
 $11,756
 $76,860
 $(36,779) $77,011
$49,626
 $12,566
 $79,905
 $(62,941) $79,156
December 31, 2016December 31, 2017
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated PartnershipParent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash and cash equivalents$
 $41
 $319
 $
 $360
$
 $(3) $309
 $
 $306
All other current assets
 2
 5,367
 
 5,369

 159
 6,063
 
 6,222
Property, plant and equipment, net
 
 50,917
 
 50,917

 
 58,437
 
 58,437
Investments in unconsolidated affiliates23,350
 10,664
 4,280
 (34,014) 4,280
48,378
 11,648
 3,816
 (60,026) 3,816
All other assets
 5
 9,260
 
 9,265

 
 9,184
 
 9,184
Total assets$23,350
 $10,712
 $70,143
 $(34,014) $70,191
$48,378
 $11,804
 $77,809
 $(60,026) $77,965
                  
Current liabilities$(1,761) $(3,800) $11,764
 $
 $6,203
$(1,496) $(3,660) $12,150
 $
 $6,994
Non-current liabilities299
 7,313
 30,148
 (299) 37,461
21,604
 7,607
 7,609
 
 36,820
Noncontrolling interest
 
 1,297
 
 1,297

 
 5,882
 
 5,882
Total partners’ capital24,812
 7,199
 26,934
 (33,715) 25,230
28,270
 7,857
 52,168
 (60,026) 28,269
Total liabilities and equity$23,350
 $10,712
 $70,143
 $(34,014) $70,191
$48,378
 $11,804
 $77,809
 $(60,026) $77,965


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Three Months Ended September 30, 2017Three Months Ended September 30, 2018
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated PartnershipParent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$
 $
 $6,973
 $
 $6,973
$
 $
 $9,641
 $
 $9,641
Operating costs, expenses, and other
 
 6,148
 
 6,148

 
 8,136
 
 8,136
Operating income
 
 825
 
 825

 
 1,505
 
 1,505
Interest expense, net
 (32) (335) 
 (367)(303) (55) (29) 
 (387)
Equity in earnings of unconsolidated affiliates647
 236
 127
 (883) 127
1,394
 501
 113
 (1,895) 113
Losses on interest rate derivatives
 
 (8) 
 (8)
Gains on interest rate derivatives45
 
 
 
 45
Other, net
 1
 71
 
 72

 
 21
 
 21
Income before income tax benefit647
 205
 680
 (883) 649
1,136
 446
 1,610
 (1,895) 1,297
Income tax benefit
 
 (112) 
 (112)
 
 (61) 
 (61)
Net income647
 205
 792
 (883) 761
1,136
 446
 1,671
 (1,895) 1,358
Less: Net income attributable to noncontrolling interest
 
 110
 
 110

 
 223
 
 223
Net income attributable to partners$647
 $205
 $682
 $(883) $651
$1,136
 $446
 $1,448
 $(1,895) $1,135
                  
Other comprehensive income$
 $
 $7
 $
 $7
$
 $
 $4
 $
 $4
Comprehensive income647
 205
 799
 (883) 768
1,136
 446
 1,675
 (1,895) 1,362
Comprehensive income attributable to noncontrolling interest
 
 110
 
 110

 
 223
 
 223
Comprehensive income attributable to partners$647
 $205
 $689
 $(883) $658
$1,136
 $446
 $1,452
 $(1,895) $1,139
Three Months Ended September 30, 2016Three Months Ended September 30, 2017*
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated PartnershipParent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$
 $
 $5,531
 $
 $5,531
$
 $
 $6,973
 $
 $6,973
Operating costs, expenses, and other
 
 4,893
 
 4,893

 
 6,194
 
 6,194
Operating income
 
 638
 
 638

 
 779
 
 779
Interest expense, net
 (39) (306) 
 (345)
 (32) (320) 
 (352)
Equity in earnings of unconsolidated affiliates119
 193
 65
 (312) 65
647
 236
 127
 (883) 127
Impairment of investment in an unconsolidated affiliate
 
 (308) 
 (308)
Losses on interest rate derivatives
 
 (28) 
 (28)
 
 (8) 
 (8)
Other, net
 
 52
 
 52

 1
 56
 
 57
Income before income tax benefit119
 154
 113
 (312) 74
647
 205
 634
 (883) 603
Income tax benefit
 
 (64) 
 (64)
 
 (112) 
 (112)
Net income119
 154
 177
 (312) 138
647
 205
 746
 (883) 715
Less: Net income attributable to noncontrolling interest
 
 21
 
 21

 
 110
 
 110
Net income attributable to partners$119
 $154
 $156
 $(312) $117
$647
 $205
 $636
 $(883) $605
                  
Other comprehensive income$
 $
 $2
 $
 $2
$
 $
 $7
 $
 $7
Comprehensive income119
 154
 179
 (312) 140
647
 205
 753
 (883) 722
Comprehensive income attributable to noncontrolling interest
 
 21
 
 21

 
 110
 
 110
Comprehensive income attributable to partners$119
 $154
 $158
 $(312) $119
$647
 $205
 $643
 $(883) $612
* As adjusted. See Note 1.


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Nine Months Ended September 30, 2017Nine Months Ended September 30, 2018
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated PartnershipParent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$
 $
 $20,444
 $
 $20,444
$
 $
 $27,331
 $
 $27,331
Operating costs, expenses, and other
 1
 18,232
 
 18,233

 
 23,910
 
 23,910
Operating income (loss)
 (1) 2,212
 
 2,211
Operating income
 
 3,421
 
 3,421
Interest expense, net
 (113) (939) 
 (1,052)(870) (137) (84) 
 (1,091)
Equity in earnings of unconsolidated affiliates1,657
 1,001
 139
 (2,658) 139
3,036
 827
 147
 (3,863) 147
Losses on interest rate derivatives
 
 (28) 
 (28)
Gain on Sunoco LP unit repurchase
 
 172
 
 172
Loss on deconsolidation of CDM
 
 (86) 
 (86)
Gains on interest rate derivatives117
 
 
 
 117
Other, net
 4
 166
 (1) 169

 
 127
 
 127
Income before income tax expense1,657
 891
 1,550
 (2,659) 1,439
Income tax expense
 
 22
 
 22
Income before income tax benefit2,283
 690
 3,697
 (3,863) 2,807
Income tax benefit
 
 (32) 
 (32)
Net income1,657
 891
 1,528
 (2,659) 1,417
2,283
 690
 3,729
 (3,863) 2,839
Less: Net income attributable to noncontrolling interest
 
 216
 
 216

 
 557
 
 557
Net income attributable to partners$1,657
 $891
 $1,312
 $(2,659) $1,201
$2,283
 $690
 $3,172
 $(3,863) $2,282
                  
Other comprehensive income$
 $
 $6
 $
 $6
$
 $
 $7
 $
 $7
Comprehensive income1,657
 891
 1,534
 (2,659) 1,423
2,283
 690
 3,736
 (3,863) 2,846
Comprehensive income attributable to noncontrolling interest
 
 216
 
 216

 
 557
 
 557
Comprehensive income attributable to partners$1,657
 $891
 $1,318
 $(2,659) $1,207
$2,283
 $690
 $3,179
 $(3,863) $2,289
Nine Months Ended September 30, 2016Nine Months Ended September 30, 2017*
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated PartnershipParent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$
 $
 $15,301
 $
 $15,301
$
 $
 $20,444
 $
 $20,444
Operating costs, expenses, and other
 1
 13,333
 
 13,334

 1
 18,245
 
 18,246
Operating income (loss)
 (1) 1,968
 
 1,967

 (1) 2,199
 
 2,198
Interest expense, net
 (116) (865) 
 (981)
 (113) (907) 
 (1,020)
Equity in earnings of unconsolidated affiliates930
 618
 260
 (1,548) 260
1,657
 1,001
 139
 (2,658) 139
Impairment of investment in an unconsolidated affiliate
 
 (308) 
 (308)
Losses on interest rate derivatives
 
 (179) 
 (179)
 
 (28) 
 (28)
Other, net
 
 96
 
 96

 4
 134
 (1) 137
Income before income tax benefit930
 501
 972
 (1,548) 855
Income tax benefit
 
 (131) 
 (131)
Income before income tax expense1,657
 891
 1,537
 (2,659) 1,426
Income tax expense
 
 22
 
 22
Net income930
 501
 1,103
 (1,548) 986
1,657
 891
 1,515
 (2,659) 1,404
Less: Net income attributable to noncontrolling interest
 
 57
 
 57

 
 266
 
 266
Net income attributable to partners$930
 $501
 $1,046
 $(1,548) $929
$1,657
 $891
 $1,249
 $(2,659) $1,138
                  
Other comprehensive loss$
 $
 $(8) $
 $(8)
Other comprehensive income$
 $
 $6
 $
 $6
Comprehensive income930
 501
 1,095
 (1,548) 978
1,657
 891
 1,521
 (2,659) 1,410
Comprehensive income attributable to noncontrolling interest
 
 57
 
 57

 
 266
 
 266
Comprehensive income attributable to partners$930
 $501
 $1,038
 $(1,548) $921
$1,657
 $891
 $1,255
 $(2,659) $1,144
* As adjusted. See Note 1.


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Nine Months Ended September 30, 2017Nine Months Ended September 30, 2018
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated PartnershipParent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows provided by operating activities$1,657
 $802
 $3,538
 $(2,660) $3,337
$2,753
 $582
 $3,843
 $(2,078) $5,100
Cash flows used in investing activities(1,348) (1,127) (4,872) 2,660
 (4,687)(834) (579) (3,732) 2,078
 (3,067)
Cash flows provided by (used in) financing activities(309) 333
 1,345
 
 1,369
Cash flows used in financing activities(1,919) 
 (41) 
 (1,960)
Change in cash
 8
 11
 
 19

 3
 70
 
 73
Cash at beginning of period
 41
 319
 
 360

 (3) 309
 
 306
Cash at end of period$
 $49
 $330
 $
 $379
$
 $
 $379
 $
 $379
Nine Months Ended September 30, 2016Nine Months Ended September 30, 2017
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated PartnershipParent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows provided by operating activities$929
 $491
 $2,593
 $(1,548) $2,465
$1,657
 $802
 $3,538
 $(2,660) $3,337
Cash flows used in investing activities(1,537) (918) (2,733) 1,548
 (3,640)(1,348) (1,127) (4,872) 2,660
 (4,687)
Cash flows provided by (used in) financing activities606
 429
 (10) 
 1,025
(309) 333
 1,345
 
 1,369
Change in cash(2) 2
 (150) 
 (150)
 8
 11
 
 19
Cash at beginning of period
 37
 490
 
 527

 41
 319
 
 360
Cash at end of period$(2) $39
 $340
 $
 $377
$
 $49
 $330
 $
 $379


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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-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 CurrentAnnual Report on Form 8-K10-K filed with the SEC on August 14, 2017.February 23, 2018. 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, 20162017 filed with the SEC on February 24, 2017 and Exhibit 99.3 to the Partnership’s Current Report on Form 8-K filed with the SEC on May 8, 2017.23, 2018.
References to “we,” “us,” “our,” the “Partnership” and “ETP” shall mean Energy Transfer Operating, L.P. (formerly Energy Transfer Partners, L.P.) and its subsidiaries. See Note 1 to the consolidated financial statements for information related to the entity’s recent name change.
OVERVIEW
The primary activities and operating subsidiaries through which we conduct those activities are as follows:
Natural gas operations, including the following:
natural gas midstream and intrastate transportation and storage; and
interstate natural gas transportation and storage.
Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.
RECENT DEVELOPMENTS
Permian Gulf Coast Pipeline Joint Venture
In September 2018, ETP, Magellan Midstream Partners, L.P., MPLX LP and Delek US Holdings, Inc. announced that they have received sufficient commitments to proceed with plans to construct a new 30-inch diameter common carrier pipeline, the Permian Gulf Coast (“PGC”) pipeline, to transport crude oil from the Permian Basin to the Texas Gulf Coast region. The 600-mile PGC pipeline system is expected to be operational in mid-2020 with multiple Texas origins. The pipeline system will have the strategic capability to transport crude oil to ETP’s Nederland, Texas terminal for ultimate delivery through its distribution system. The project is subject to receipt of customary regulatory and Board approvals of the respective entities.
ETE and ETP Simplification Transaction
In October 2018, Energy Transfer Equity, L.P. (“ETE”) and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly-owned subsidiary of ETE in a unit-for-unit exchange (the “ETE-ETP Merger”). In connection with the transaction, ETP unitholders (other than ETE and its subsidiaries) received 1.28 common units of ETE for each common unit of ETP they owned.
Immediately prior to the closing of the ETE-ETP Merger, the following also occurred:
the IDRs in ETP were converted into 1,168,205,710 ETP common units; and
the general partner interest in ETP was converted to a non-economic general partner interest and ETP issued 18,448,341 ETP common units to ETP GP.
Immediately prior to the closing of the ETE-ETP Merger, ETE contributed the following to ETP:
2,263,158 common units representing limited partner interests in Sunoco LP to ETP in exchange for 2,874,275 ETP common units;
100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETP in exchange for 42,812,389 ETP common units;
12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETP in exchange for 16,134,903 ETP common units; and


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a 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC to ETP in exchange for 37,557,815 ETP common units.
Series D Preferred Units Issuance
In July 2018, ETP issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $445 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes.
ETP Senior Notes Offering and Redemption
In October 2017, the Partnership redeemed all of the outstandingJune 2018, ETP issued $500 million aggregate principal amount of ETLP’s 6.50%4.20% senior notes due July 2021 and all2023, $1.00 billion aggregate principal amount of the outstanding $7004.95% senior notes due 2028, $500 million aggregate principal amount of ETLP’s 5.50%5.80% 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 20272038 and $1.50$1.00 billion aggregate principal amount of 5.40%6.00% senior notes due 2047.2048. The $2.22$2.96 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5%outstanding senior notes, due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit FacilityETP’s revolving credit facility and for general partnership purposes.
August 2017 Units OfferingOld Ocean Joint Venture Formation
In August 2017,May 2018, ETP and Enterprise Products Partners L.P. announced the Partnershipformation of a joint venture to resume service on the Old Ocean natural gas pipeline. The 24-inch diameter pipeline resumed service in May 2018 and ETP is the operator. Additionally, both parties are in the process of expanding their jointly owned North Texas 36-inch pipeline that will provide more capacity from West Texas for deliveries into the Old Ocean pipeline. The North Texas pipeline expansion project is expected to be complete by January 1, 2019.
Acquisition of HPC
ETP previously owned a 49.99% interest in HPC, which owns RIGS.  In April 2018, ETP acquired the remaining 50.01% interest in HPC.  Prior to April 2018, HPC was reflected as an unconsolidated affiliate in ETP’s financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in ETP’s financial statements.
Series C Preferred Units Issuance
In April 2018, ETP issued 5418 million ETP common unitsof its 7.375% Series C Preferred Units at a price of $25 per unit, resulting in an underwritten public offering. Nettotal gross proceeds of $997 million from the offering$450 million. The proceeds were used by the Partnership to repay amounts outstanding under itsETP’s revolving credit facilities, to fund capital expendituresfacility and for general partnership purposes.
RoverCDM Contribution Agreement
In July 2017,On April 2, 2018, ETP announcedcontributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units are a new class of partnership interests of USAC that it had entered intohave substantially all of the rights and obligations of a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”),USAC common unit, except the USAC Class B Units will not participate in distributions 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 throughfirst four quarters following the closing date alongof April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019.
In connection with the paymentCDM Contribution, ETE acquired (i) all of additional amounts subjectthe outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC, and (ii) 12,466,912 USAC common units for cash consideration equal to certain adjustments. The transaction closed in October 2017.  As a result of this closing, Rover Holdco is now owned 50.1% by$250 million.
New Ethane Export Facility Joint Venture
In March 2018, ETP and 49.9% by Blackstone.Satellite Petrochemical USA Corp. (“Satellite”) entered into definitive agreements to form a joint venture, Orbit Gulf Coast NGL Exports, LLC (“Orbit”), with the purpose of constructing a new export terminal on the United States Gulf Coast to provide ethane to Satellite for consumption at their ethane cracking facilities in China. At the terminal, Orbit will construct an 800 MBbls refrigerated ethane storage tank, a 175 MBbls/d ethane refrigeration facility and a 20-inch ethane pipeline originating at ETP’s Mont Belvieu Fractionators that will make deliveries to the terminal as well as domestic markets in the region. ETP will be the operator of the Orbit assets, provide storage and marketing services for Satellite and provide Satellite with approximately 150 MBbls/d of ethane under a long-term, demand-based agreement. Additionally, ETP will construct and


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PennTex Tender Offerwholly own the infrastructure that is required to both supply ethane to the pipeline and Limited Call Right Exerciseto load the ethane on to very large ethane carriers destined for Satellite’s newly constructed ethane crackers in China’s Jiangsu Province. Subject to Chinese Governmental approval, it is anticipated that the Orbit export terminal will be ready for commercial service in the fourth quarter of 2020.
Sunoco LP Common Unit Repurchase
In JuneFebruary 2018, after the record date for Sunoco LP’s fourth quarter 2017 ETP purchased all of the outstanding PennTexcash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units not previously owned by ETP for $20.00 per common unit in cash.aggregate cash consideration of approximately $540 million. ETP now owns allused the proceeds from the sale of the economic interests of PennTex, and PennTexSunoco LP common units areto repay amounts outstanding under its revolving credit facility.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Effective December 22, 2017, 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 publicly traded or listedpermit 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 because it is non-binding policy and parties will have the opportunity to address the policy as applied in future cases. 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 NASDAQ.treatment of income taxes may have on the rates ETP can charge for the FERC regulated transportation services are unknown at this time.
Sunoco Logistics MergerThe FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) 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 ETP can charge for FERC regulated transportation services.
In April 2017, Energy Transfer Partners, L.P.Included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and Sunoco Logistics completed the merger transaction (the “Sunoco Logistics Merger”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: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates only as required related to the Tax Act and the Revised Policy Statement, commit to filing a general NGA Section 4 rate case in which Sunoco Logistics acquired Energy Transfer Partners, L.P.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 are scheduled to file their respective FERC Form No. 501-Gs by November 8, 2018. Rover, FGT, Transwestern and MEP are scheduled to file their respective FERC Form No. 501-Gs by December 6, 2018. At this time, we cannot predict the outcome of the Final Rule, but adoption of the regulation could ultimately result in a unit-for-unit transaction. Underrate proceeding that may impact the termsrates ETP is permitted to charge its customers for FERC regulated transportation services.
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


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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 transaction,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 unitholders received 1.5 common unitscost of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Underservice rates to be affected by the termsRevised 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 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.
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 dateultimate outcome of the contribution, including $547 million of intangible assetsNOI, the Final Rule, and $435 million of property, plant and equipment.
In July 2017, the Partnership 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 increaseRevised Policy Statement, combined with the reduced corporate federal income tax rate established in the Partnership’s ownership interest in PEPTax Act. The extent of any revenue reduction related to approximately 88%. The Partnership maintainsour cost of service rates, if any, will depend on a controlling financial and voting interest in PEP and is the operatordetailed review of all of ETP’s cost of service components and the assets. As such, PEPoutcomes of any challenges to our rates by the FERC or our shippers.
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 reflectedused to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a consolidated subsidiaryresult of the Partnership. ExxonMobil’s interestPipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in PEP is reflected as noncontrolling interestresponse 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 consolidated balance sheets. ExxonMobil’s contribution resultedUnited States.
Interstate Liquids Transportation Regulation
The FERC utilizes an indexing rate methodology which, as currently in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest”effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the consolidated statementProducer Price Index, or PPI. The indexing methodology is applicable to existing rates, with the exclusion of equity.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in whichmarket-based rates. The FERC’s indexing methodology is subject to review every five years. During the Partnership indirectly owns a 100% membership interest, sold a 49% interestfive-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize the FERC liquids index to change transportation rates annually every July 1. With respect to liquids and refined products pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on Page 700 of FERC Form No. 6. This information will be used by the FERC in its wholly-owned subsidiary, Bakken Pipeline Investments LLC,next five year review of the liquids pipeline index to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporationgenerate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and Enbridge Energy Partners, L.P.,the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. The FERC’s establishment of a just and reasonable rate, including the determination of the appropriate liquids pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in eachincome taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination 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, the Partnership contributed a portionappropriate pipeline index. Accordingly, depending on the FERC’s application of its ownership interestindexing 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 Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.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 earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt 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).adjustments. Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s 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- GAAPnon-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’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 total or consolidated Adjusted EBITDA is consistent with the definition of Segment Adjusted EBITDA above.
As discussed in Note 1 of the Partnership’s consolidated financial statements included in “Item 1. Financial Statements,” during the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain


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inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.
Consolidated Results
Three Months Ended
September 30,
   Nine Months Ended
September 30,
  Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
2017 2016 Change 2017 2016 Change2018 2017* Change 2018 2017* Change
Segment Adjusted EBITDA:          

          

Intrastate transportation and storage$163
 $133
 $30
 $480
 $461
 $19
$221
 $163
 $58
 $621
 $480
 $141
Interstate transportation and storage273
 278
 (5) 800
 848
 (48)416
 273
 143
 1,069
 800
 269
Midstream356
 314
 42
 1,088
 875
 213
434
 356
 78
 1,225
 1,088
 137
NGL and refined products transportation and services423
 383
 40
 1,196
 1,072
 124
498
 439
 59
 1,410
 1,208
 202
Crude oil transportation and services396
 169
 227
 830
 521
 309
682
 420
 262
 1,694
 835
 859
All other133
 113
 20
 363
 395
 (32)78
 133
 (55) 242
 363
 (121)
Total1,744
 1,390
 354
 4,757
 4,172
 585
2,329
 1,784
 545
 6,261
 4,774
 1,487
Depreciation, depletion and amortization(596) (503) (93) (1,713) (1,469) (244)(636) (596) (40) (1,827) (1,713) (114)
Interest expense, net(367) (345) (22) (1,052) (981) (71)(387) (352) (35) (1,091) (1,020) (71)
Losses on interest rate derivatives(8) (28) 20
 (28) (179) 151
Non-cash unit-based compensation expense(19) (22) 3
 (57) (60) 3
Gain on Sunoco LP common unit repurchase
 
 
 172
 
 172
Loss on deconsolidation of CDM
 
 
 (86) 
 (86)
Gains (losses) on interest rate derivatives45
 (8) 53
 117
 (28) 145
Non-cash compensation expense(20) (19) (1) (61) (57) (4)
Unrealized gains (losses) on commodity risk management activities(81) (15) (66) 17
 (96) 113
97
 (81) 178
 (255) 17
 (272)
Inventory valuation adjustments86
 37
 49
 30
 143
 (113)
Adjusted EBITDA related to unconsolidated affiliates(279) (240) (39) (765) (711) (54)(257) (279) 22
 (670) (765) 95
Equity in earnings of unconsolidated affiliates127
 65
 62
 139
 260
 (121)113
 127
 (14) 147
 139
 8
Impairment of investment in an unconsolidated affiliate
 (308) 308
 
 (308) 308
Other, net42
 43
 (1) 111
 84
 27
13
 27
 (14) 100
 79
 21
Income before income tax expense (benefit)649
 74

575

1,439
 855
 584
Income tax expense (benefit)(112) (64) (48) 22
 (131) 153
Income before income tax (expense) benefit1,297
 603

694

2,807
 1,426
 1,381
Income tax (expense) benefit61
 112
 (51) 32
 (22) 54
Net income$761
 $138
 $623
 $1,417
 $986
 $431
$1,358
 $715
 $643
 $2,839
 $1,404
 $1,435
* As adjusted.
See the detailed discussion of Segment Adjusted EBITDA and Segment Operating Results.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased for the three and nine months ended September 30, 20172018 compared to the same periodsperiod last year primarily due to additional depreciation from assets recently placed in serviceservice. These increases were partially offset by the deconsolidation of CDM in April 2018, which reduced depreciation and recent acquisitions.amortization expense by $43 million and $78 million for the three and nine months ended September 30, 2018, respectively, compared to the prior periods.
Interest Expense, net. Interest expense, net of capitalized interest, increased for the three and nine months ended September 30, 20172018 compared to the same periodsperiod last year primarily attributable to increases in long-term debt includingfrom ETP senior note issuances, partially offset by a decrease in credit facility borrowings.


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Gain on Sunoco LP Common Unit Repurchase. In connection with Sunoco LP’s repurchase of its common units in February 2018, the Dakota Access and ETCO term loans that became effective in August 2016.Partnership recognized a gain of $172 million during the nine months ended September 30, 2018.
LossesLoss on Deconsolidation of CDM. In connection with the CDM Contribution in April 2018, the Partnership deconsolidated CDM and recognized a loss of $86 million during the nine months ended September 30, 2018.
Gains (Losses) on Interest Rate Derivatives. LossesGains on interest rate derivatives during the three and nine months ended September 30, 2017 and 20162018 resulted from decreasesincreases in forward interest rates, which caused our forward-starting swaps to change in value.
Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional information on the unrealized gains (losses) on commodity risk management activities included in “Segment Operating Results” below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for crude oil, NGLs and refined products inventories as a result of commodity price changes during the respective periods.


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Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.
Other, net. Includes amortization of regulatory assets and other income and expense amounts.
Income Tax Expense (Benefit).(Expense) Benefit. For the nine months ended September 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $68 million during the period. In addition, for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. The three and nine months ended September 30, 2017 also reflect increased income tax expense due to higher earnings among the Partnership’s consolidated corporate subsidiaries. For the three and nine months ended September 30, 2016,2018 compared to the Partnership’ssame period last year, income tax expense decreased primarily due to the decrease in federal corporate income tax rate per the Tax Act as well as $109 million and $179 million, respectively, of deferred tax benefit primarily resulted from losses amongadjustments during the Partnership’s consolidated corporate subsidiaries.three and nine months ended September 30, 2018 as the result of a state statutory rate reduction.



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Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
Three Months Ended
September 30,
   Nine Months Ended
September 30,
  Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
Equity in earnings (losses) of unconsolidated affiliates:                      
Citrus$35
 $31
 $4
 $86
 $80
 $6
$42
 $35
 $7
 $102
 $86
 $16
FEP14
 12
 2
 39
 38
 1
14
 14
 
 41
 39
 2
PES11
 (26) 37
 5
 (25) 30
MEP9
 9
 
 29
 31
 (2)7
 9
 (2) 24
 29
 (5)
HPC5
 8
 (3) 17
 23
 (6)
Sunoco LP35
 16
 19
 (89) 54
 (143)29
 35
 (6) (106) (89) (17)
USAC(4) 
 (4) (6) 
 (6)
Other18
 15
 3
 52
 59
 (7)25
 34
 (9) 92
 74
 18
Total equity in earnings of unconsolidated affiliates$127
 $65
 $62
 $139
 $260
 $(121)$113
 $127
 $(14) $147
 $139
 $8
                      
Adjusted EBITDA related to unconsolidated affiliates(1):
                      
Citrus$99
 $90
 $9
 $262
 $251
 $11
$96
 $99
 $(3) $256
 $262
 $(6)
FEP18
 19
 (1) 55
 56
 (1)19
 18
 1
 56
 55
 1
PES15
 (19) 34
 31
 2
 29
MEP23
 22
 1
 66
 69
 (3)20
 23
 (3) 62
 66
 (4)
HPC13
 15
 (2) 40
 45
 (5)
Sunoco LP74
 83
 (9) 211
 208
 3
58
 74
 (16) 126
 211
 (85)
USAC20
 
 20
 41
 
 41
Other37
 30
 7
 100
 80
 20
44
 65
 (21) 129
 171
 (42)
Total Adjusted EBITDA related to unconsolidated affiliates$279
 $240
 $39
 $765
 $711
 $54
$257
 $279
 $(22) $670
 $765
 $(95)
                      
Distributions received from unconsolidated affiliates:                      
Citrus$50
 $50
 $
 $113
 $112
 $1
$52
 $50
 $2
 $125
 $113
 $12
FEP18
 17
 1
 28
 47
 (19)18
 18
 
 50
 28
 22
MEP13
 17
 (4) 106
 56
 50
9
 13
 (4) 40
 106
 (66)
HPC9
 13
 (4) 22
 38
 (16)
Sunoco LP36
 36
 
 108
 102
 6
21
 36
 (15) 79
 108
 (29)
USAC10
 
 10
 20
 
 20
Other18
 16
 2
 58
 49
 9
34
 27
 7
 76
 80
 (4)
Total distributions received from unconsolidated affiliates$144
 $149
 $(5) $435
 $404
 $31
$144
 $144
 $
 $390
 $435
 $(45)
(1) 
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.  
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.


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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.


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Unrealized gains or losses on commodity risk management activitiesand 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 Marginmargin 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 Marginmargin is similar to the GAAP measure of gross margin, except that Segment Marginsegment margin excludes charges for depreciation, depletion and amortization.
In addition, for certain segments, the sections below include information on the components of Segment Marginsegment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of Segment Marginsegment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of Segment Marginsegment margin are calculated consistent with the calculation of Segment Margin;segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
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 affiliates. These reclassifications had no impact on net income or total equity.
Following is a reconciliation of Segment MarginETP’s segment margin to operating income, as reported in the Partnership’sits consolidated statements of operations:
Three Months Ended
September 30,
 Nine Months Ended
September 30,
Three Months Ended
September 30,
 Nine Months Ended
September 30,
2017 2016 2017 20162018 2017 2018 2017
Segment Margin:       
Intrastate transportation and storage$167
 $172
 $551
 $525
$284
 $167
 $722
 $551
Interstate transportation and storage224
 236
 666
 729
395
 224
 1,039
 666
Midstream530
 476
 1,614
 1,350
622
 530
 1,768
 1,614
NGL and refined products transportation and services488
 484
 1,563
 1,357
634
 483
 1,821
 1,558
Crude oil transportation and services588
 266
 1,202
 852
944
 548
 1,954
 1,194
All other112
 79
 290
 258
25
 112
 177
 290
Intersegment eliminations(12) (26) (24) (50)(8) (13) (23) (24)
Total Segment Margin2,097
 1,687
 5,862
 5,021
Total segment margin2,896
 2,051
 7,458
 5,849
              
Less:              
Operating expenses571
 475
 1,603
 1,359
632
 571
 1,863
 1,603
Depreciation, depletion and amortization596
 503
 1,713
 1,469
636
 596
 1,827
 1,713
Selling, general and administrative105
 71
 335
 226
123
 105
 347
 335
Operating income$825
 $638
 $2,211
 $1,967
$1,505
 $779
 $3,421
 $2,198


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Intrastate Transportation and Storage
Three Months Ended
September 30,
   Nine Months Ended
September 30,
  Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
Natural gas transported (MMBtu/d)8,942,066
 8,289,826
 652,240
 8,695,047
 8,392,641
 302,406
Natural gas transported (BBtu/d)12,146
 8,951
 3,195
 10,592
 8,698
 1,894
Withdrawals from storage natural gas inventory (BBtu)
 
 
 17,703
 23,093
 (5,390)
Revenues$773
 $758
 $15
 $2,342
 $1,857
 $485
$922
 $773
 $149
 $2,610
 $2,342
 $268
Cost of products sold606
 586
 20
 1,791
 1,332
 459
638
 606
 32
 1,888
 1,791
 97
Segment margin167
 172
 (5) 551
 525
 26
284
 167
 117
 722
 551
 171
Unrealized (gains) losses on commodity risk management activities22
 (7) 29
 16
 24
 (8)(12) 22
 (34) 33
 16
 17
Operating expenses, excluding non-cash compensation expense(40) (43) 3
 (124) (117) (7)(51) (40) (11) (141) (124) (17)
Selling, general and administrative expenses, excluding non-cash compensation expense(6) (5) (1) (17) (17) 
(7) (6) (1) (20) (17) (3)
Adjusted EBITDA related to unconsolidated affiliates19
 15
 4
 53
 45
 8
6
 19
 (13) 26
 53
 (27)
Other1
 1
 
 1
 1
 
1
 1
 
 1
 1
 
Segment Adjusted EBITDA$163
 $133
 $30
 $480
 $461
 $19
$221
 $163
 $58
 $621
 $480
 $141
Volumes. For the three and nine months ended September 30, 20172018 compared to the same periodsperiod last year, transported volumes increased primarily due to higher demand for exports to Mexico, along withfavorable market pricing, as well as the additionimpact of new pipes to our intrastate pipeline system. These increases were partially offset by lower production volumesreflecting RIGS as a consolidated subsidiary beginning in the Barnett Shale region.April 2018, as discussed in “Recent Developments” above.
Segment Margin. The components of ourETP’s intrastate transportation and storage segment margin were as follows:
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2017 2016 Change 2017 2016 Change
Transportation fees$108
 $122
 $(14) $337
 $381
 $(44)
Natural gas sales and other42
 26
 16
 140
 81
 59
Retained fuel revenues14
 14
 
 48
 34
 14
Storage margin, including fees3
 10
 (7) 26
 29
 (3)
Total segment margin$167
 $172
 $(5) $551
 $525
 $26
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2018 2017 Change 2018 2017 Change
Transportation fees$141
 $109
 $32
 $392
 $337
 $55
Natural gas sales and other (excluding unrealized gains and losses)110
 55
 55
 309
 149
 160
Retained fuel revenues (excluding unrealized gains and losses)16
 15
 1
 42
 43
 (1)
Storage margin (excluding unrealized gains and losses)5
 10
 (5) 12
 38
 (26)
Unrealized gains (losses) on commodity risk management activities12
 (22) 34
 (33) (16) (17)
Total segment margin$284
 $167
 $117
 $722
 $551
 $171
Segment Adjusted EBITDA. For the three months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to ourETP’s intrastate transportation and storage segment increased due to the net impacts of the following:
an increase of $55 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity;
an increase of $7 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to new contracts and the impact of the Red Bluff Express pipeline coming online in May 2018; and
a net increase of $6 million due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of


53

Table of Contents

$25 million, $5 million and $2 million, respectively, and a decrease of $12 million in Adjusted EBITDA related to unconsolidated affiliates; partially offset by
a decrease of $5 million in realized storage margin primarily due to lower realized derivative gains.
Segment Adjusted EBITDA. For the nine months ended September 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to ETP’s intrastate transportation and storage segment increased due to the net impacts of the following:
an increase of $160 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity;
an increase of $6 million in transportation fees, excluding the impact of consolidating RIGS as discussed above, primarily due to new contracts and the impact of the Red Bluff Express pipeline coming online in May 2018; and
a net increase of $3 million due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $49 million, $11 million and $4 million, respectively, and a decrease of $31 million in Adjusted EBITDA related to unconsolidated affiliates; partially offset by
a decrease of $26 million in realized storage margin primarily due to an adjustment to the Bammel storage inventory; and
a decrease of $1 million in retained fuel revenues due to lower natural gas pricing.
Interstate Transportation and Storage
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2018 2017 Change 2018 2017 Change
Natural gas transported (BBtu/d)10,155
 6,075
 4,080
 9,029
 5,678
 3,351
Natural gas sold (BBtu/d)18
 19
 (1) 17
 18
 (1)
Revenues$395
 $224
 $171
 $1,039
 $666
 $373
Operating expenses, excluding non-cash compensation, amortization and accretion expenses(97) (79) (18) (296) (220) (76)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses(19) (14) (5) (53) (33) (20)
Adjusted EBITDA related to unconsolidated affiliates135
 140
 (5) 374
 383
 (9)
Other2
 2
 
 5
 4
 1
Segment Adjusted EBITDA$416
 $273
 $143
 $1,069
 $800
 $269
Volumes. For the three months ended September 30, 2018 compared to the same period last year, transported volumes reflected an increase of 2,225 BBtu/d as a result of the initiation of service on the Rover pipeline; increases of 772 BBtu/d and 625 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to increased utilization of higher contracted capacity; and an increase of 398 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale and deliveries into intrastate markets.
For the nine months ended September 30, 2018 compared to the same period last year, transported volumes reflected increases of 1,817 BBtu/d as a result of the initiation of service on the Rover pipeline; increases of 594 BBtu/d and 428 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to higher demand resulting from colder weather and increased utilization by the Rover pipeline; 397 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale and deliveries into the intrastate markets and 104 BBtu/d on the Transwestern pipeline resulting from favorable market opportunities in the midcontinent and Waha areas from the Permian supply basin.
Segment Adjusted EBITDA. For the three months ended September 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to ETP’s interstate transportation and storage segment increased due to the net impacts of the following:
an increase of $29$128 million associated with the Rover pipeline with increases of $149 million in natural gas salesrevenues, $14 million in net operating expenses and other (excluding net changes$7 million in unrealized gainsselling, general and lossesadministrative expenses; and


54

Table of $13 million)Contents

an aggregate increase of $22 million in revenues, excluding the incremental revenue related to the Rover pipeline discussed above, primarily due to capacity sold at higher realized gains from pipeline optimization activity;
rates on the Transwestern and Panhandle pipelines; partially offset by
an increase of $9 million in storage margin (excluding net changes in unrealized gains and losses of $16 million related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below;
a decrease of $3$4 million in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to the timingslightly higher system gas expense and higher maintenance project costs due to scope and level of project related expenses of $3 million, lower allocated expenses and lower capitalized overhead of $2 million, partiallyactivity, offset by higher outside serviceslower ad valorem taxes due to favorable valuations; and employee expenses
a decrease of $2 million; and
an increase of $4$5 million in Adjusted EBITDA related to unconsolidated affiliates dueprimarily related to two new joint venture pipelines placed in service in 2017; partially offset by
a decrease in transportation feessale of $14 million due to renegotiated contracts resulting incapacity on MEP at lower billed volumes, offset by increased margin from optimization activity recorded in natural gasrates and lower sales and other.


44


short term firm capacity on Citrus.
Segment Adjusted EBITDA. For the nine months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to our intrastateETP’s interstate transportation and storage segment increased due to the net impacts of the following:
An increase of $247 million associated with the Rover pipeline with increases of $336 million in revenues, $70 million in net operating expenses and $19 million in selling, general and administrative expenses; and
an aggregate increase of $45 million in revenues, excluding the incremental revenues related to the Rover pipeline discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by $8 million of lower reservation revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by
an increase of $63$6 million in natural gas sales and other (excluding net changes in unrealized gains and losses of $4 million)operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to higher realized gains from pipeline optimization activity;maintenance project costs; and
a decrease of $11 million in storage margin (excluding net changes in unrealized gains and losses of $8 million related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below;
an increase of $10 million in retained fuel sales (excluding net changes in unrealized gains and losses of $4 million) primarily due to higher market prices. The average spot price at the Houston Ship Channel location increased 34% for the nine months ended September 30, 2017 compared to the same period last year;
an increase of $7 million in operating expenses primarily due to higher compression fuel expense of $6 million and higher maintenance and general expenses of $7 million, offset by lower allocated expenses of $3 million, lower capitalized overhead of $2 million and timing of project expenses of $1 million; and
an increase of $8$9 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to two new joint venture pipelines placed in service in 2017;lower sales of short term firm capacity on Citrus and lower margins on MEP due to lower rates on renewals of expiring long term contracts, partially offset by lower legal fees on Citrus.
a decrease in transportation fees of $44 million due to renegotiated contracts resulting in lower billed volumes, offset by increased margin from optimization activity recorded in natural gas sales and other and an increase of $8 million due to new demand billings on our Houston Pipeline system.
Storage margin was comprised of the following:Midstream
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2017 2016 Change 2017 2016 Change
Withdrawals from storage natural gas inventory (MMBtu)
 11,547,500
 (11,547,500) 23,092,500
 33,205,000
 (10,112,500)
Realized margin on natural gas inventory transactions$5
 $(3) $8
 $18
 $33
 $(15)
Fair value inventory adjustments(10) (4) (6) (46) 52
 (98)
Unrealized gains (losses) on derivatives2
 12
 (10) 34
 (74) 108
Margin recognized on natural gas inventory, including related derivatives(3) 5
 (8) 6
 11
 (5)
Revenues from fee-based storage6
 5
 1
 20
 18
 2
Total storage margin$3
 $10
 $(7) $26
 $29
 $(3)
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2018 2017 Change 2018 2017 Change
Gathered volumes (BBtu/d)12,774
 11,090
 1,684
 11,890
 10,764
 1,126
NGLs produced (MBbls/d)583
 453
 130
 533
 461
 72
Equity NGLs (MBbls/d)32
 27
 5
 31
 27
 4
Revenues$2,253
 $1,765
 $488
 $5,741
 $5,017
 $724
Cost of products sold1,631
 1,235
 396
 3,973
 3,403
 570
Segment margin622
 530
 92
 1,768
 1,614
 154
Unrealized (gains) losses on commodity risk management activities
 1
 (1) 
 (18) 18
Operating expenses, excluding non-cash compensation expense(179) (157) (22) (512) (470) (42)
Selling, general and administrative expenses, excluding non-cash compensation expense(19) (26) 7
 (59) (60) 1
Adjusted EBITDA related to unconsolidated affiliates9
 6
 3
 25
 20
 5
Other1
 2
 (1) 3
 2
 1
Segment Adjusted EBITDA$434
 $356
 $78
 $1,225
 $1,088
 $137
The changes in storage margin were due primarilyVolumes. For the three and nine months ended September 30, 2018 compared to the movementsame periods last year, gathered volumes and NGL production increased primarily due to increases in market price of the physical storage gasNorth Texas, Permian and the financial derivatives used to hedge that gas.Northeast regions, partially offset by smaller declines in other regions.


4555


Interstate Transportation and StorageSegment Margin. The components of ETP’s midstream segment margin were as follows:
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2017 2016 Change 2017 2016 Change
Natural gas transported (MMBtu/d)6,074,783
 5,385,679
 689,104
 5,678,016
 5,527,607
 150,409
Natural gas sold (MMBtu/d)19,012
 19,478
 (466) 17,659
 19,398
 (1,739)
Revenues$224
 $236
 $(12) $666
 $729
 $(63)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses(79) (76) (3) (220) (223) 3
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses(14) (13) (1) (33) (36) 3
Adjusted EBITDA related to unconsolidated affiliates140
 131
 9
 383
 376
 7
Other2
 
 2
 4
 2
 2
Segment Adjusted EBITDA$273
 $278
 $(5) $800
 $848
 $(48)
Volumes. For the three months ended September 30, 2017 compared to the same period last year, transported volumes reflected increases of 157,060 MMBtu/d on the Trunkline pipeline as a result of increased backhaul deliveries, 153,401 MMBtu/d on the Tiger pipeline due to an increase in production in the Haynesville Shale, and 142,207 MMBtu/d on the Transwestern pipeline as a result of weather driven demand in the West and opportunities in the Texas intrastate market. The remainder of the increase was primarily due to the Rover pipeline, which was placed in partial service on August 31, 2017.
For the nine months ended September 30, 2017 compared to the same period last year, transported volumes increased due to the placement in partial service of the Rover pipeline effective August 31, 2017 and 59,305 MMBtu/d on the Tiger pipeline due to an increase in production in the Haynesville Shale and opportunities in the Texas intrastate market.
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2018 2017 Change 2018 2017 Change
Gathering and processing fee-based revenues$456
 $418
 $38
 $1,330
 $1,262
 $68
Non-fee-based contracts and processing (excluding unrealized gains and losses)166
 113
 53
 438
 334
 104
Unrealized gains (losses) on commodity risk management activities
 (1) 1
 
 18
 (18)
Total segment margin$622
 $530
 $92
 $1,768
 $1,614
 $154
Segment Adjusted EBITDA. For the three months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storageETP’s midstream segment decreasedincreased due to the net effectimpacts of the following:
an increase of $38 million in fee-based margin due to growth in the North Texas, Permian and Northeast regions, offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions;
an increase of $27 million in non-fee-based margin due to increased throughput volume in the South Texas and Permian regions;
an increase of $26 million in non-fee-based margin primarily due to higher crude oil and NGL prices;
a decrease of $7 million in reservation revenues of $16 million on the Panhandle, Trunklineselling, general and Transwestern pipelines andadministrative expenses primarily due to a decrease of $3 million in gas parking servicemerger and acquisition costs and a $3 million change in capitalized overhead; and
an increase of $3 million in Adjusted EBITDA related revenues on the Panhandle and Trunkline pipelines, primarilyto unconsolidated affiliates due to lackhigher earnings from ETP’s Aqua, Mi Vida and Ranch joint ventures; partially offset by
an increase of customer demand driven by weak spreads and mild weather. In addition, revenues on the Tiger pipeline decreased $3$22 million due to contract restructuring. These decreases were offset by $10 million of revenues from the placement in partial service of the Rover pipeline effective August 31, 2017; and
an increase in operating expenses of $3 million primarily due to higher ad valorem taxes resulting from higher valuations; offset by
an increaseincreases of $6 million in income from unconsolidated joint ventures of $9materials, $5 million primarily due toin outside services and $4 million in maintenance project costs, as well as a legal settlement and lower operating expenses on Citrus.
$7 million change in capitalized overhead.
Segment Adjusted EBITDA. For the nine months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net effect of the following:
a decrease in reservation revenues of $41 million on the Panhandle, Trunkline and Transwestern pipelines and a decrease of $11 million in gas parking service related revenues on the Panhandle and Trunkline pipelines, primarily due to lack of customer demand driven by weak spreads and mild weather, decrease of $17 million in revenues on the Tiger pipeline due to contract restructuring, and a decrease of $4 million on the Sea Robin pipeline due to producer maintenance and production declines. The decreases above were offset by $10 million of revenues from the placement in partial service of the Rover pipeline effective August 31, 2017;
a decrease in operating expenses of $3 million primarily due to lower allocated costs of $7 million and lower lease storage expense of $3 million, partially offset by higher ad valorem taxes resulting from higher valuations; and
a decrease in selling, general and administrative expenses of $3 million due to refunds associated with legal fees, insurance premiums and franchise taxes; offset by


46


an increase in income from unconsolidated joint ventures of $7 million primarily due to a legal settlement and lower operating expenses on Citrus, partially offset by lower earnings from Midcontinent Express.
Midstream
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2017 2016 Change 2017 2016 Change
Gathered volumes (MMBtu/d)11,090,285
 9,675,003
 1,415,282
 10,764,317
 9,853,930
 910,387
NGLs produced (Bbls/d)449,454
 420,877
 28,577
 442,190
 440,124
 2,066
Equity NGLs (Bbls/d)27,185
 34,341
 (7,156) 26,936
 31,847
 (4,911)
Revenues$1,765
 $1,343
 $422
 $5,017
 $3,765
 $1,252
Cost of products sold1,235
 867
 368
 3,403
 2,415
 988
Segment margin530
 476
 54
 1,614
 1,350
 264
Unrealized (gains) losses on commodity risk management activities1
 
 1
 (18) 
 (18)
Operating expenses, excluding non-cash compensation expense(157) (153) (4) (470) (453) (17)
Selling, general and administrative expenses, excluding non-cash compensation expense(26) (17) (9) (60) (42) (18)
Adjusted EBITDA related to unconsolidated affiliates6
 7
 (1) 20
 19
 1
Other2
 1
 1
 2
 1
 1
Segment Adjusted EBITDA$356
 $314
 $42
 $1,088
 $875
 $213
Volumes. Gathered volumes and NGL production increased during the three and nine months ended September 30, 2017 compared to the same periods last year primarily due to recent acquisitions, including PennTex, and gains in the Permian and Northeast regions, partially offset by basin declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions.
Segment Margin. The components of our midstream segment margin were as follows:
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2017 2016 Change 2017 2016 Change
Gathering and processing fee-based revenues$422
 $391
 $31
 $1,264
 $1,171
 $93
Non fee-based contracts and processing108
 85
 23
 350
 179
 171
Total segment margin$530
 $476
 $54
 $1,614
 $1,350
 $264
Segment Adjusted EBITDA. For the three months ended September 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to ourETP’s midstream segment increased due to the net effects of the following:
an increase of $24 million (excluding net changes in unrealized gains and losses of $1 million) in non-fee based margin due to higher crude oil and NGL prices;
an increase of $16 million in fee-based revenue due to minimum volume commitments in the South Texas region, as well as volume increases in the Permian and Northeast regions. These increases were partially offset by volume declines in South Texas, North Texas and the Mid-Continent/Panhandle regions; and
an increase of $15 million in fee-based revenue due to recent acquisitions, including PennTex; partially offset by
an increase of $4 million in operating expenses primarily due to recent acquisitions, including PennTex; and
an increase in selling, general and administrative expenses primarily due to an increase in shared services allocation.


47


Segment Adjusted EBITDA. For the nine months ended September 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effectsimpacts of the following:
an increase of $113$68 million in non-fee basedfee-based margin due to growth in the North Texas, Permian and Northeast regions, offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions;
an increase of $57 million in non-fee-based margin primarily due to higher crude oil and NGL prices;
an increase of $38$47 million (excluding net changes in unrealized gains and losses of $20 million) in non-fee basednon-fee-based margin due to increased throughput volume increases in the Permian, partially offset by declines in the South Texas, North Texas and Mid-Continent/PanhandlePermian regions;
an increase of $36$5 million in fee-based revenueAdjusted EBITDA related to unconsolidated affiliates due to minimum volume commitments in the South Texas region, as well as volume increases in the Permianhigher earnings from ETP’s Aqua, Mi Vida and Northeast regions. These increases were partially offset by volume declines in the South Texas, North Texas and the Mid-Continent/Panhandle regions;Ranch joint ventures; and
an increasea decrease of $57$1 million in fee-based revenueselling, general and administrative expenses primarily due to recent acquisitions, including PennTex;lower office expenses; partially offset by
an increase of $17$42 million in operating expenses primarily due to recent acquisitions, including PennTex; and
an increaseincreases of $18$13 million in general and administrative expenses primarily due to a decrease ofoutside services, $12 million in materials, $8 million in employee costs and $4 million in maintenance project costs as well as a $3 million change in capitalized overhead, a $13 million increase in shared services allocation and $6 million additional costs from the PennTex acquisition. These increases were partially offset by a favorable impactoverhead.


56


NGL and Refined Products Transportation and Services
Three Months Ended
September 30,
   Nine Months Ended
September 30,
  Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
NGL transportation volumes (MBbls/d)836
 766
 70
 827
 741
 86
1,086
 836
 250
 997
 829
 168
Refined products transportation volumes (MBbls/d)612
 611
 1
 626
 573
 53
627
 612
 15
 628
 626
 2
NGL and refined products terminal volumes (MBbls/d)782
 822
 (40) 793
 782
 11
858
 782
 76
 784
 780
 4
NGL fractionation volumes (MBbls/d)390
 338
 52
 418
 350
 68
567
 390
 177
 505
 418
 87
Revenues$2,070
 $1,545
 $525
 $6,115
 $4,329
 $1,786
$3,063
 $2,070
 $993
 $8,177
 $6,115
 $2,062
Cost of products sold1,582
 1,061
 521
 4,552
 2,972
 1,580
2,429
 1,587
 842
 6,356
 4,557
 1,799
Segment margin488
 484
 4
 1,563
 1,357
 206
634
 483
 151
 1,821
 1,558
 263
Unrealized losses on commodity risk management activities56
 21
 35
 2
 53
 (51)26
 56
 (30) 26
 2
 24
Operating expenses, excluding non-cash compensation expense(105) (109) 4
 (358) (319) (39)(168) (106) (62) (448) (358) (90)
Selling, general and administrative expenses, excluding non-cash compensation expense(13) (12) (1) (49) (41) (8)(17) (13) (4) (52) (49) (3)
Adjusted EBITDA related to unconsolidated affiliates19
 21
 (2) 54
 53
 1
23
 19
 4
 63
 54
 9
Inventory valuation adjustments(22) (22) 
 (17) (31) 14
Other
 
 
 1
 
 1

 
 
 
 1
 (1)
Segment Adjusted EBITDA$423
 $383
 $40
 $1,196
 $1,072
 $124
$498
 $439
 $59
 $1,410
 $1,208
 $202
Volumes. For the three and nine months ended September 30, 20172018 compared to the same periods last year, NGL transportation volumes increased primarily from the Permian region resulting from a ramp up in production from existing customers, higher throughput volumes on Mariner West driven by end user facility constraints in the prior period and refinedhigher throughput from Mariner South.
Refined products transportation volumes increased in the major producing regions, including the Permian, Southeast Texas, Louisiana, Eagle Ford and North Texas.
NGL and refined products terminal volumes decreased for the three and nine months ended September 30, 20172018 compared to the same periods last year primarily due to higher throughput volumes from the sale of one of our refined product terminals in April 2017. Northeast and Southwest regions, partially offset by decreased throughput volumes from the Midwest region.
NGL and refined products terminal volumes increased for the three months ended September 30, 2018 compared to the same period last year primarily due to more volumes loaded at ETP’s Nederland terminal as propane export demand increased, as well as higher throughput volumes at ETP’s Marcus Hook Industrial Complex primarily due to increased production from the Marcellus region. For the nine months ended September 30, 20172018 compared to the same period last year, NGL and refined products terminal volumes increased primarily due to more volumes loaded at ETP’s Nederland terminal as propane export demand increased, partially offset by lower refined product throughput volumes at our Marcus Hook Industrial Complex from the Northeast producing regions.ETP’s Eagle Point terminal and lower volumes at ETP’s refined products marketing terminals.


48


Average daily fractionated volumes at ETP’s Mont Belvieu, Texas fractionation facility increased 17%45% and 23%21% for the three and nine months ended September 30, 2017,2018, respectively, compared to the same periods last year primarily due to the commissioning of our fourthETP’s fifth fractionator at Mont Belvieu, Texas, in October 2016, which has a capacity of 120,000 Bbls/d,July 2018 as well as increased producer volumes as mentioned above.from Permian producers.


57


Segment Margin. The components of ourETP’s NGL and refined products transportation and services segment margin were as follows:
Three Months Ended
September 30,
   Nine Months Ended
September 30,
  Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
Fractionators and Refinery services margin$117
 $103
 $14
 $352
 $296
 $56
Fractionators and refinery services margin$162
 $115
 $47
 $424
 $352
 $72
Transportation margin246
 226
 20
 720
 629
 91
322
 246
 76
 878
 720
 158
Storage margin50
 50
 
 160
 148
 12
50
 50
 
 154
 160
 (6)
Terminal Services margin90
 83
 7
 258
 239
 19
Terminal services margin109
 90
 19
 294
 258
 36
Marketing margin(15) 22
 (37) 73
 45
 28
17
 38
 (21) 97
 70
 27
Unrealized losses on commodity risk management activities(26) (56) 30
 (26) (2) (24)
Total segment margin$488
 $484
 $4
 $1,563
 $1,357
 $206
$634
 $483
 $151
 $1,821
 $1,558
 $263
Segment Adjusted EBITDA. For the three months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to ourETP’s NGL and refined products transportation and services segment increased due to the net impactimpacts of the following:
an increase of $76 million in transportation margin of $20due to a $63 million primarilyincrease resulting from higher producer volumes from the Permian region on ETP’s Texas NGL pipelines, an $11 million increase due to higher throughput volumes on our Texas NGL pipelinesMariner West driven by end user facility constraints in the prior period, an $8 million increase due to higher throughput volumes from the Eagle Ford and ourBarnett regions, a $3 million increase due to higher throughput volumes in ETP’s Northeast refined products system and a $3 million increase due to higher throughput volumes on Mariner South and Mariner East system;
1 NGL systems. These increases were partially offset by a $7 million decrease resulting from the timing of deficiency revenue recognition and a $5 million decrease from lower volumes from the Southeast Texas region;
an increase of $47 million in fractionation and refinery services margin of $13 million (excluding net changes in unrealized gains and losses of $1 million) primarily due to a $40 million increase resulting from the commissioning of ETP’s fifth fractionator in July 2018 and higher NGL volumes from most major producing regions,the Permian region feeding ETP’s Mont Belvieu fractionation facility, a $4 million increase from Mariner South as noted above;
more cargoes were loaded due to increased demand for export and a $3 million increase from blending gains as a result of improved market pricing; and
an increase of $19 million in terminal services margin due to a $9 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses, a $6 million increase at ETP’s Nederland terminal due to increased demand for propane exports and a $6 million increase due to higher throughput at ETP’s Marcus Hook Industrial Complex. These increases were partially offset by a $2 million decrease due to reduced rental fees at ETP’s Eagle Point facility; partially offset by
an increase of $62 million in operating expenses due to increases of $25 million from higher throughput on ETP’s fractionator, pipeline and terminal assets and the commissioning of ETP’s fifth fractionator in July 2018, $10 million due to a legal settlement in the prior period, $9 million resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, $7 million due to the timing of maintenance projects and higher terminal volumes from the Mariner NGL projects;overhead allocations, $6 million due to environmental reserves and
$5 million due to ad valorem tax expense; and
a decrease of $4$21 million in operating expensesmarketing margin primarily due to a legal settlement$13 million decrease in optimization gains from ETP’s Mont Belvieu marketing activities, a $4 million decrease from sales of $8 millionpropane and other products at ETP’s Marcus Hook Industrial Complex and a quarterly ad valorem tax true-up of $1 million; partially offset by
$2 million decrease from ETP’s butane blending operations resulting from a decrease of $1 million in marketing margin (excluding net changes in unrealized gains and losses of $36 million) primarily due to the timing of the recognition of margin from optimization activities; and
an increase of $1 million in selling, general and administrative expenses due to higher allocations and lower capitalized overhead resulting from reduced capital spending.blending volumes.
Segment Adjusted EBITDA. For the nine months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to ourETP’s NGL and refined products transportation and services segment increased due to the net impactimpacts of the following:
an increase in storage margin of $12$158 million primarily due to increased volumes from our Mont Belvieu fractionators;
an increase in transportation margin of $91due to a $141 million primarilyincrease resulting from higher producer volumes from the Permian region on ETP’s Texas NGL pipelines, a $22 million increase due to higher throughput volumes on our Texas NGL pipelinesMariner West driven by end user facility constraints in the prior period, an $11 million increase resulting from a reclassification between ETP’s transportation and our Mariner East system;
anfractionation margins in the second quarter of 2018, a $4 million increase in fractionation and refinery services margin of $55 million (excluding net changes in unrealized gains and losses of $1 million) primarily due to higher NGLthroughput volumes from most major producing regions, as noted above;
anthe Barnett region, a $4 million increase in terminal services margin of $19 million due to higher terminalthroughput volumes from the Mariner NGL projects;ETP’s Northeast and
an Southwest refined product systems and a $4 million increase of $22 million in marketing margin (excluding net changes in unrealized gains and losses 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 of $15 million, higher ad valorem tax expenses of $11 million (primarily from our Lone Star Express pipeline beginning service in 2016), higher employee expenses associated with assets placed in service of $5 million and project related service expenses of $5 million; and
an increase of $8 million in selling, general and administrative expenses due to higher allocations and lower capitalized overheadthroughput volumes on Mariner South due to system downtime in the prior period. These increases were partially offset by a $16 million decrease resulting from reduced capital spending.lower throughput on Mariner


4958


East 1 due to system downtime in 2018, a $10 million decrease due to lower transported volumes from the Southeast Texas region and a $2 million decrease resulting from the timing of deficiency revenue recognition;
an increase of $72 million in fractionation and refinery services margin due to a $63 million increase resulting from the commissioning of ETP’s fifth fractionator in July 2018 and higher NGL volumes from the Permian region feeding ETP’s Mont Belvieu fractionation facility, a $12 million increase from blending gains as a result of improved market pricing and an $8 million increase as more cargoes were loaded at ETP’s Mariner South export facility. These increases were partially offset by an $11 million decrease resulting from a reclassification between ETP’s transportation and fractionation margins;
an increase of $36 million in terminal services margin due to a $25 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses, a $13 million increase at ETP’s Nederland terminal due to increased demand for propane exports and a $2 million increase due to favorable activity at ETP’s Marcus Hook Industrial Complex. These increases were partially offset by a $3 million decrease due to reduced rental fees at ETP’s Eagle Point facility and a $1 million decrease from ETP’s marketing terminal volumes primarily due to the sale of one of ETP’s terminals in April 2017;
an increase of $27 million in marketing margin primarily due to a $17 million increase from ETP’s butane blending operations and an $11 million increase from sales of domestic propane and other products at ETP’s Marcus Hook Industrial Complex due to more favorable market prices; and
an increase of $9 million in Adjusted EBITDA related to unconsolidated affiliates due to improved contributions from ETP’s unconsolidated refined products joint venture interests; partially offset by
an increase of $90 million in operating expenses primarily due to increases of $44 million from higher throughput on ETP’s fractionator, pipeline and terminal assets and the commissioning of ETP’s fifth fractionator in July 2018, $25 million resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, $10 million due to a legal settlement in the prior period, $10 million due to environmental reserves and $4 million due to the timing of maintenance projects and higher overhead allocations; and
a decrease of $6 million in storage margin primarily due to a $15 million decrease from the expiration and amendments to various NGL and refined products storage contracts, partially offset by an increase from throughput pipeline fees collected at ETP’s Mont Belvieu storage terminal.
Crude Oil Transportation and Services
Three Months Ended
September 30,
   Nine Months Ended
September 30,
  Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
Crude Transportation Volumes (MBbls/d)3,758
 2,686
 1,072
 3,401
 2,500
 901
Crude Terminals Volumes (MBbls/d)1,923
 1,559
 364
 1,877
 1,524
 353
Crude transportation volumes (MBbls/d)4,276
 3,773
 503
 4,119
 3,425
 694
Crude terminals volumes (MBbls/d)2,134
 1,923
 211
 2,060
 1,884
 176
Revenues$2,725
 $1,856
 $869
 $7,765
 $5,146
 $2,619
$4,438
 $2,725
 $1,713
 $12,986
 $7,765
 $5,221
Cost of products sold2,137
 1,590
 547
 6,563
 4,294
 2,269
3,494
 2,177
 1,317
 11,032
 6,571
 4,461
Segment margin588
 266
 322
 1,202
 852
 350
944
 548
 396
 1,954
 1,194
 760
Unrealized gains on commodity risk management activities(1) 
 (1) (3) 
 (3)
Unrealized (gains) losses on commodity risk management activities(118) (1) (117) 187
 (3) 190
Operating expenses, excluding non-cash compensation expense(119) (71) (48) (305) (185) (120)(126) (119) (7) (397) (305) (92)
Selling, general and administrative expenses, excluding non-cash compensation expense(13) (16) 3
 (62) (44) (18)(22) (13) (9) (64) (62) (2)
Adjusted EBITDA related to unconsolidated affiliates5
 5
 
 11
 10
 1
4
 5
 (1) 14
 11
 3
Inventory valuation adjustments(64) (15) (49) (13) (112) 99
Segment Adjusted EBITDA$396
 $169
 $227
 $830
 $521
 $309
$682
 $420
 $262
 $1,694
 $835
 $859
Volumes. For the three and nine months ended September 30, 2018 crude transportation volumes increased due to placing the Bakken pipeline in service in June 2017 as well as higher throughput on existing pipelines due to increased production in West Texas. For the three and nine months ended September 30, 2018 crude terminal volumes benefited from an increase in barrels delivered to ETP’s Nederland crude terminal from the Bakken pipeline and from increased West Texas production.


59


Segment Adjusted EBITDA. For the three months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to ourETP’s crude oil transportation and services segment increased due to the net impacts of the following:
an increase of $194$279 million in segment margin (excluding unrealized losses on commodity risk management activities) due to the following: a $131 million increase resulting from higher throughput, primarily from ETP’s Bakken pipeline and from Permian producers on existing pipeline assets, as well as a $30 million increase resulting primarily from placing our Bakken PipelineETP’s Permian Express 3 pipeline in service in the secondfourth quarter of 2017, as well as the acquisition2017; a $108 million increase (excluding a net change of a$117 million in unrealized gains and losses) from ETP’s crude oil gathering system inacquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas;
anTexas and Gulf Coast markets; and a $10 million increase of $28 million from existing assets due to increased volumes throughout the system;higher throughput and
an increase of $18 million due to the impact of LIFO accounting; ship loading fees at ETP’s Nederland terminal; partially offset by
an increase of $9 million in selling, general and administrative expenses primarily due to increases of $4 million in overhead allocations, $2 million in employee costs and $2 million in insurance costs; and
additionalan increase of $7 million in operating expense asexpenses due to a result of$5 million increase due to higher throughput related expenses on existing assets and a $2 million increase from placing other new projectsETP’s Permian Express 3 pipeline in service and costs associated with increased volumes on our system.
in the fourth quarter of 2017.
Segment Adjusted EBITDA. For the nine months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to ourETP’s crude oil transportation and services segment increased due to the net impacts of the following:
an increase of $389$950 million in segment margin (excluding unrealized losses on commodity risk management activities) primarily due to the following: a $541 million increase resulting primarily from placing ourETP’s Bakken Pipelinepipeline in service in the second quarter of 2017, as well as the acquisition2017; a $86 million increase resulting from higher throughput, primarily from Permian producers, on existing pipeline assets; a $295 million increase (excluding a net change of a$190 million in unrealized gains and losses) from ETP’s crude oil gathering system inacquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas;Texas and Gulf Coast markets; and a $25 million increase primarily from higher throughput and ship loading fees at ETP’s Nederland terminal; and
an increase of $11$3 million from existing assetsin Adjusted EBITDA related to unconsolidated affiliates due to increased volumes throughout the system;jet fuel sales from ETP’s joint ventures; partially offset by
a decreasean increase of $29$92 million in operating expenses due to the impact of LIFO accounting. This unfavorable LIFO impact is expected to be reversed in future periods as commodity prices fall or the inventory positions are liquidated; and
additional operating expense as a result of$37 million increase primarily resulting from placing other new projectsETP’s Bakken pipeline in service in the second quarter of 2017; a $36 million increase to throughput related costs on existing assets; a $19 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; a $7 million increase in overhead allocations; and costs associated with increased volumes on our system.a $4 million increase from ad valorem taxes; partially offset by an $11 million decrease in insurance and environmental related expenses.
All Other
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2018 2017 Change 2018 2017 Change
Revenues$525
 $683
 $(158) $1,598
 $2,249
 $(651)
Cost of products sold500
 571
 (71) 1,421
 1,959
 (538)
Segment margin25
 112
 (87) 177
 290
 (113)
Unrealized (gains) losses on commodity risk management activities7
 3
 4
 9
 (14) 23
Operating expenses, excluding non-cash compensation expense(9) (34) 25
 (50) (86) 36
Selling, general and administrative expenses, excluding non-cash compensation expense(26) (34) 8
 (63) (82) 19
Adjusted EBITDA related to unconsolidated affiliates80
 88
 (8) 168
 244
 (76)
Other and eliminations1
 (2) 3
 1
 11
 (10)
Segment Adjusted EBITDA$78
 $133
 $(55) $242
 $363
 $(121)


5060


All Other
 Three Months Ended
September 30,
   Nine Months Ended
September 30,
  
 2017 2016 Change 2017 2016 Change
Revenues$683
 $956
 $(273) $2,249
 $2,521
 $(272)
Cost of products sold571
 877
 (306) 1,959
 2,263
 (304)
Segment margin112
 79
 33
 290
 258
 32
Unrealized (gains) losses on commodity risk management activities3
 1
 2
 (14) 19
 (33)
Operating expenses, excluding non-cash compensation expense(34) (20) (14) (86) (57) (29)
Selling, general and administrative expenses, excluding non-cash compensation expense(34) (14) (20) (82) (60) (22)
Adjusted EBITDA related to unconsolidated affiliates88
 63
 25
 244
 209
 35
Other and eliminations(2) 4
 (6) 11
 26
 (15)
Segment Adjusted EBITDA$133
 $113
 $20
 $363
 $395
 $(32)
Amounts reflected in ourETP’s all other segment primarily include:
ourETP’s equity method investment in limited partnership units of Sunoco LP consisting of 26.2 million and 43.5 million Sunoco LP common units, representing 31.8% and 43.7% of Sunoco LP’s total outstanding common units;units as of September 30, 2018 and September 30, 2017, respectively. The results above reflect Sunoco LP’s repurchase of 17,286,859 Sunoco LP common units owned by ETP in February 2018; however, the results above do not reflect ETE’s contribution of limited partner and general partner interests in Sunoco LP to ETP in connection with the ETE-ETP Merger in October 2018.  For periods subsequent to the ETE-ETP Merger, ETP will reflect Sunoco LP as a consolidated subsidiary;
ourETP’s natural gas marketing and compression operations;
operations. Subsequent to ETP’s contribution of CDM to USAC in April 2018, ETP’s all other segment includes ETP’s equity method investment in USAC consisting of 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests. The results above do not reflect ETE’s contribution of limited partner and general partner interests in USAC to ETP in connection with the ETE-ETP Merger in October 2018.  For periods subsequent to the ETE-ETP Merger, ETP will reflect USAC as a consolidated subsidiary;
a non-controlling interest in PES. Prior to PES’s reorganization in August 2018, ETP’s 33% interest in PES comprising 33% of PES' outstanding common units;was reflected as an unconsolidated affiliate; subsequent the August 2018 reorganization, ETP holds an approximately 8% interest in PES and
no longer reflects PES as an affiliate; and
ourETP’s investment in Coal Handling, an entity that owns and operates end-user coal handling facilities.
Segment Adjusted EBITDA. For the three months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to ourETP’s all other segment increased primarilydecreased due to the net impactimpacts of the following:
an increasea decrease of $25$16 million in Adjusted EBITDA related to unconsolidated affiliates reflectingfrom ETP’s investment in Sunoco LP resulting from ETP’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018;
a decrease of $12 million due to ETP’s contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM contribution;
a decrease of $34$12 million in Adjusted EBITDA related to unconsolidated affiliates from ourETP’s investment in PES offset by a decreaseprimarily due to ETP’s lower ownership in PES subsequent to its reorganization, which resulted in PES no longer being reflected as an affiliate beginning in the third quarter of $9 million from our investment in Sunoco LP;
2018;
an increase of $7 million in general and administrative expenses from higher professional expenses;
a decrease of $6 million due to losses from commodity trading and risk management activities; and
an increasea decrease of $4$3 million primarily due to lower margin from ourETP’s compression operations; partially offset by
an increase of $11 million in transaction related expenses; and
an increase of $9 million in operating expenses related to an equipment lease buyout.
business.
Segment Adjusted EBITDA. For the nine months ended September 30, 20172018 compared to the same period last year, Segment Adjusted EBITDA related to ourETP’s all other segment decreased primarily due to the net impactimpacts of the following:
a decrease of $66 million related to the termination of management fees paid by ETE that ended in 2016; and
an increase of $39 million in transaction related expenses; partially offset by
an increase of $35$85 million in Adjusted EBITDA related to unconsolidated affiliates primarily comprising increasesfrom ETP’s investment in Sunoco LP resulting from ETP’s lower ownership in Sunoco LP and lower operating results of $29Sunoco LP due to the sale of the majority of its retail assets in January 2018;
a decrease of $31 million in Adjusted EBITDA related to unconsolidated affiliates from ourETP’s investment in PES primarily due to ETP’s lower ownership in PES subsequent to its reorganization, which resulted in PES no longer being reflected as an affiliate beginning in the third quarter of 2018, as well as lower Adjusted EBITDA prior to August 2018; and $3
a decrease of $21 million from ourdue to ETP’s contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in Sunoco LP;USAC held by ETP subsequent to the CDM Contribution; partially offset by
an increase of $15$10 million in Adjusted EBITDA primarily due to lower transport fees of $6 million resulting from commodity trading activities;the expiration of a capacity commitment on ETP’s Trunkline pipeline and a $7 million decrease in losses from the mark-to-market of physical system gas, offset by lower optimization gains on residue gas sales;
an increase of $6 million due to increased margin from ETP’s compression equipment business as several large projects were completed in June 2018; and
an increase of $4 million due to an equipment lease buyout in August 2017, partially offset by lower expenses related to our compression operations.margin from depressed gas prices in West Texas.


5161


LIQUIDITY AND CAPITAL RESOURCES
Overview
ETP’s ability to satisfy its obligations and pay distributions to its Unitholdersunitholders 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 management’s control.
We currently expect capital expenditures in 2018 to be within the following ranges (excluding capital expenditures related to the businesses contributed to ETP in connection with the ETE-ETP Merger in October 2018):
 Growth Maintenance
 Low High Low High
Intrastate transportation and storage$275
 $300
 $30
 $35
Interstate transportation and storage (1)
675
 700
 115
 120
Midstream975
 1,025
 130
 135
NGL and refined products transportation and services2,100
 2,150
 60
 70
Crude oil transportation and services (1)
425
 450
 90
 100
All other (including eliminations)50
 75
 60
 65
Total capital expenditures$4,500
 $4,700
 $485
 $525
(1)
Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.
For the year ending December 31, 2017,2019, we expect to spend approximately $4.1 billion on capital expenditure funding, net of $1.0 billion financed at the asset level and net an approximately $1.4 billion reduction related to the sale of a portion of our interest in the Rover pipeline project. For 2018, we expect to spend approximately $3$5 billion on organic growth projects.
The assets used in our 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, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we include these factors in our anticipated growth capital expenditures for each year.
We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally fund growth capital expenditures with proceeds of borrowings under credit facilities, long-term debt, the issuance of additional common units, dropdown proceeds or the monetization of non-core assets or a combination thereof.
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 include regulatory changes, the price for our 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 net changes in operating assets and liabilities.liabilities (net of effects of acquisitions and deconsolidations). Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash unit-based 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 have 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 derivative assets and liabilities, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchase and sales of inventories and the timing of advances and deposits received from customers.


62


Nine months ended September 30, 20172018 compared to nine months ended September 30, 2016.2017. Cash provided by operating activities during 20172018 was $3.34$5.10 billion compared to $2.47$3.34 billion for 20162017 and net income was $1.42$2.84 billion and $986 million$1.40 billion for 20172018 and 2016,2017, respectively. The difference between net income and cash provided by operating activities for the nine months ended September 30, 20172018 primarily consisted of net changes in operating assets and liabilities (net of $185effects of acquisitions and deconsolidations) of $451 million and other non-cash items totaling $1.44$1.51 billion.
The non-cash activity in 20172018 and 20162017 consisted primarily of depreciation, depletion and amortization of $1.83 billion and $1.71 billion, respectively, and $1.47 billion, respectively, non-cash compensation expense of $61 million and $57 million, respectively. Unconsolidated affiliate activity in 2018 and $60 million, respectively, and2017 consisted of equity in earnings of unconsolidated affiliates of$147 million and $139 million, respectively, and $260distributions received of $328 million and $319 million, respectively. Non-cash activity in 20172018 also included deferred income taxesa gain on the sale of $1Sunoco LP units of $172 million and inventory valuation adjustmentsa loss on the deconsolidation of $30 million. Non-cash activity in 2016 also included impairmentCDM of investment in an unconsolidated affiliate of $308$86 million.
Cash paid for interest, net of interest capitalized, was $1.03 billion$996 million and $1.10$1.01 billion for the nine months ended September 30, 20172018 and 2016,2017, respectively.
Capitalized interest was $177$221 million and $148$211 million for the nine months ended September 30, 2018 and 2017, and 2016, respectively.


52


Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.
Nine months ended September 30, 20172018 compared to nine months ended September 30, 2016.2017. Cash used in investing activities during 20172018 was $4.69$3.07 billion compared to $3.64$4.69 billion for 2016.in 2017. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 20172018 were $6.06$4.87 billion compared to $5.74$6.06 billion for 2016.2017. Additional detail related to our capital expenditures is provided in the table below. During 2018, we received $1.23 billion in cash related to the CDM Contribution and $540 million in cash related to the Sunoco LP common unit repurchase. During 2017, we received $2.00 billion in cash related to the Bakken equity sale to MarEn Bakken Company LLC, paid $280 million in cash for the acquisition of PennTex noncontrolling interest and paid $264 million in cash for all other acquisitions. During 2016, we received $2.20 billion in cash related to the contribution of our Sunoco, Inc. retail business to Sunoco LP.
The following is a summary of capital expenditures (net of contributions in aid of construction costs) for the nine months ended September 30, 2017:2018:
Capital Expenditures Recorded During PeriodCapital Expenditures Recorded During Period
Growth Maintenance TotalGrowth Maintenance Total
Intrastate transportation and storage$34
 $22
 $56
$233
 $37
 $270
Interstate transportation and storage1,704
 50
 1,754
470
 73
 543
Midstream914
 76
 990
731
 113
 844
NGL and refined products transportation and services2,106
 53
 2,159
1,494
 44
 1,538
Crude oil transportation and services331
 36
 367
333
 33
 366
All other (including eliminations)128
 49
 177
43
 42
 85
Total capital expenditures$5,217
 $286
 $5,503
$3,304
 $342
 $3,646
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.
Nine months ended September 30, 20172018 compared to nine months ended September 30, 2016.2017. Cash used in financing activities during 2018 was $1.96 billion compared to provided by financing activities during 2017 wasof $1.37 billion compared to $1.03 billion for 2016.2017. In 20172018 and 2016,2017, we received net proceeds from Common UnitETP common unit offerings of $58 million and $2.16 billion, and $794 million, respectively. In 2016, our subsidiaries2018, we received $1.31 billion in net proceeds$867 million from the issuance of common units.preferred unit offerings. During 2017,2018, we had a net increase in our debt level of $1.24 billion$410 million compared to a net increase of $1.76$1.24 billion for 2016.2017. We have paid distributions of $3.14 billion to ETP’s unitholders in 2018 compared to $2.54 billion to our partners in 2017 compared to $2.67 billion in 2016.2017. We have also paid distributions of $306$536 million to noncontrolling interests in 20172018 compared to $334$306 million in 2016.2017. In addition, we have received capital contributions of $919$438 million in cash from noncontrolling interests in 20172018 compared


63


to $187$919 million in 2016.2017. During 2018, we also repurchased ETP common units for cash of $24 million and incurred debt issuance costs of $42 million. During 2017, we also repurchased our outstanding Legacy ETP Preferred Units for cash of $53 million and incurred debt issuance costs of $50 million.
Off-Balance Sheet Arrangements
Guarantee of Sunoco LP Notes
In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to certain of Sunoco LP’s senior notes and $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes, repaid and terminated the term loan and issued the following notes (the “Sunoco LP Notes”) for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
$1.00 billion aggregate principal amount of 4.875% senior notes due 2023;
$800 million aggregate principal amount of 5.50% senior notes due 2026; and
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.
In connection with the issuance of the Sunoco LP Notes, Sunoco LP entered into a registration rights agreement with the initial purchasers pursuant to which Sunoco LP agreed to complete an offer to exchange the Sunoco LP Notes for an issue of registered notes with terms substantively identical to each series of Sunoco LP Notes and evidencing the same indebtedness as the Sunoco LP Notes on or before January 23, 2019.


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Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
ETP Senior Notes(1)$20,540
 $19,440
$28,755
 $27,005
Transwestern Senior Notes575
 657
575
 575
Panhandle Senior Notes1,085
 1,085
386
 785
Sunoco, Inc. Senior Notes65
 465
Sunoco Logistics Senior Notes7,600
 5,350
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
ETP $5.00 billion Revolving Credit Facility due December 2023 (2)
1,780
 2,292
ETP $1.00 billion 364-Day Credit Facility due November 2019
 50
Bakken Project $2.50 billion Credit Facility due August 20192,500
 1,100
2,500
 2,500
PennTex $275 million Revolving Credit Facility due December 2019
 168
Other long-term debt5
 30
4
 5
Unamortized premiums, net of discounts and fair value adjustments76
 116
35
 61
Deferred debt issuance costs(197) (180)(188) (179)
Total debt34,340
 32,930
33,847
 33,094
Less: current maturities of long-term debt710
 1,189
2,649
 407
Long-term debt, less current maturities$33,630
 $31,741
$31,198
 $32,687
(1) 
Includes $2.06 billion$400 million aggregate principal amount of 9.70% senior notes due March 15, 2019 and $777$450 million aggregate principal amount of commercial paper outstanding at9.00% senior notes due April 15, 2019 that were classified as long-term as of September 30, 20172018 as management has the intent and December 31, 2016, respectively.ability to refinance the borrowings on a long-term basis.
(2) 
Includes $50 million$1.57 billion and $2.01 billion of commercial paper outstanding at September 30, 2018 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 2017.2017, respectively.
ETP Senior Notes Offering and Redemption
In October 2017,June 2018, ETP issued the Partnership redeemed all of the outstanding $500following senior notes:
$500 million aggregate principal amount of ETLP’s 6.50%4.20% senior notes due July 2021 and all2023;
$1.00 billion aggregate principal amount of the outstanding $7004.95% senior notes due 2028;
$500 million aggregate principal amount of ETLP’s 5.50%5.80% senior notes due April 2023. The2038; and
$1.00 billion aggregate principal amount paid to redeem theseof 6.00% senior notes including call premiums, was approximately $1.23 billion.
ETP Senior Notes Offering due 2048.
In September 2017,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 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 ETP’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETP 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 subsidiarysenior unsecured basis so long as it guarantees any of ETP, issued $750 million aggregate principal amountour other long-term debt. The guarantee for each series of 4.00%notes ranks equally in right of payment with all of the existing and future senior notes due 2027 and $1.50 billion aggregate principal amountdebt of 5.40%Sunoco Logistics Partners Operations L.P., including its senior notes due 2047. notes.
The $2.22$2.96 billion net proceeds from the offering were used to repay borrowings outstanding under ETP’s revolving credit facility, for general partnership purposes and to redeem all of the $500following senior notes:
ETP’s $650 million aggregate principal amount of ETLP’s 6.5%2.50% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility (described below)June 15, 2018;
Panhandle’s $400 million aggregate principal amount of 7.00% senior notes due June 15, 2018; and for general partnership purposes.
Credit Facilities and Commercial Paper
ETLP Credit FacilityETP’s $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018.
The ETLP Credit Facility allows for borrowings of upaggregate amount paid 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 whichredeem these notes was commercial paper.approximately $1.65 billion.


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Sunoco Logistics Credit Facilities and Commercial Paper
ETP maintains the Sunoco Logistics $2.50 billion unsecuredFive-Year Credit Facility
ETP’s revolving credit facility (the “Sunoco Logistics“ETP Five-Year Credit Facility”), which matures previously allowed for unsecured borrowings up to $4.00 billion and matured in March 2020.December 2022. On October 19, 2018, the ETP Five-Year Credit Facility was amended to increase the borrowing capacity by $1.00 billion, to $5.00 billion, and to extend the maturity date to December 1, 2023. The Sunoco LogisticsETP 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 September 30, 2017,2018, the Sunoco LogisticsETP Five-Year Credit Facility had $35$1.78 billion outstanding, of which $1.57 billion was commercial paper. The amount available for future borrowings was $2.06 billion after taking into account letters of credit of $163 million, but before taking into account the additional capacity from the October 19, 2018 amendment. The weighted average interest rate on the total amount outstanding as of September 30, 2018 was 3.00%.
ETP 364-Day Facility
ETP’s 364-day revolving credit facility (the “ETP 364-Day Facility”) previously allowed for unsecured borrowings up to $1.00 billion and matured on November 30, 2018. On October 19, 2018, the ETP 364-Day Facility was amended to extend the maturity date to November 29, 2019. As of September 30, 2018, the ETP 364-Day Facility had no outstanding borrowings.
In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on 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, the 364-Day Credit Facility was terminated and repaid in May 2017.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco LogisticsETP and Phillips 66 completed project-level financing of the Bakken Pipeline.pipeline. The $2.50 billion credit facility provides substantially all of the remaining capital necessary to complete the projects.matures in August 2019 (the “Bakken Credit Facility”). As of September 30, 2017,2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings, all of which has been reflected in current maturities of long-term debt on the Partnership’s consolidated balance sheet included in “Item 1. Financial Statements.” The weighted average interest rate on the total amount outstanding as of September 30, 2018 was outstanding under this credit facility.
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”)3.85%. In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.
Covenants Related to Our Credit Agreements
We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, 2017.2018.
CASH DISTRIBUTIONS
Following the Sunoco Logistics Merger, cash distributions areDistributions on common units declared and paid in accordance withby the Partnership’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreementPartnership subsequent to December 31, 2017 but prior to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the endclosing of the quarter, less reserves established by the general partnerETE-ETP Merger as discussed in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership 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 holdersNote 1 of the Partnership’s common units:consolidated financial statements included in “Item 1. Financial Statements,” were as follows:
    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.
Quarter Ended Record Date Payment Date Rate
December 31, 2017 February 8, 2018 February 14, 2018 $0.5650
March 31, 2018 May 7, 2018 May 15, 2018 0.5650
June 30, 2018 August 6, 2018 August 14, 2018 0.5650


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Following are distributionsDistributions on ETP’s preferred units declared and/or paid by the Partnership subsequent to the Sunoco Logistics Merger:December 31, 2017 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
The total amounts of distributions declared for the periods presented (all from Available Cash from our 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
Period Ended Record Date Payment Date Rate
Series A Preferred Units      
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
June 30, 2018 August 1, 2018 August 15, 2018 31.250
Series B Preferred Units      
December 31, 2017 February 1, 2018 February 15, 2018 $16.378
June 30, 2018 August 1, 2018 August 15, 2018 33.125
Series C Preferred Units      
June 30, 2018 August 1, 2018 August 15, 2018 $0.5634
September 30, 2018 November 1, 2018 November 15, 2018 0.4609
Series D Preferred Units      
September 30, 2018 November 1, 2018 November 15, 2018 $0.5931
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 23, 2018. 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 99.3 to its Form 8-K filed on May 8, 2017. The following information is provided to supplement the Form 8-K disclosures specifically related to impairment of long-lived assets and goodwill.revenue recognition.
Impairment of Long-Lived Assets and Goodwill.  Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.RECENT ACCOUNTING PRONOUNCEMENTS
In order to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations.
The Partnership determined the fair value of its reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the


56


overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
One key assumption for the measurement of goodwill impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks describedSee Note 1 in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used1. Financial Statements” included in this Quarterly Report for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period.
The goodwill impairments recorded by the Partnership during the years ended December 31, 2016 and 2015 represented all of the goodwill within the respective reporting units.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 included in Exhibit 99.3 to the Partnership’s CurrentAnnual Report on Form 8-K10-K for the year ended December 31, 2017 filed with the SEC on May 8, 2017,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 for the year ended December 31, 2016.2017. Since December 31, 20162017, there have been no material changes to our primary market risk exposures or how those exposures are managed.


5767


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, 2016September 30, 2018 December 31, 2017
Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% ChangeNotional 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):           
Fixed Swaps/Futures1,297,500
 $
 $
 (682,500) $
 $
358
 $
 $
 1,078
 $
 $
Basis Swaps IFERC/NYMEX(1)
(15,810,000) (4) 
 2,242,500
 (1) 
69,685
 8
 1
 48,510
 2
 1
Options – Puts13,000,000
 
 
 
 
 
(17,273) 
 
 13,000
 
 
Power (Megawatt):                      
Forwards665,040
 
 2
 391,880
 (1) 1
429,720
 6
 
 435,960
 1
 1
Futures(213,840) 
 1
 109,564
 
 
309,123
 (1) 1
 (25,760) 
 
Options – Puts(280,800) 1
 2
 (50,400) 
 
157,435
 1
 
 (153,600) 
 1
Options – Calls545,600
 
 1
 186,400
 1
 
321,240
 ���
 
 137,600
 
 
Crude (Bbls) – Futures(160,000) 1
 1
 (617,000) (4) 6
Crude (MBbls) – Futures
 
 
 
 1
 
(Non-Trading)                      
Natural Gas (MMBtu):           
Natural Gas (BBtu):           
Basis Swaps IFERC/NYMEX67,500
 (3) 2
 10,750,000
 2
 
(7,705) (45) 14
 4,650
 (13) 4
Swing Swaps IFERC91,897,500
 (1) 
 (5,662,500) (1) 1
69,145
 
 2
 87,253
 (2) 1
Fixed Swaps/Futures(20,220,000) 1
 7
 (52,652,500) (27) 19
(1,784) 1
 1
 (4,700) (1) 2
Forward Physical Contracts(140,937,993) 3
 43
 (22,492,489) 1
 8
(54,151) 5
 
 (145,105) 6
 41
Natural Gas Liquid (Bbls) – Forwards/Swaps(8,747,200) (48) 79
 (5,786,627) (40) 35
Refined Products (Bbls) – Futures(701,000) 
 9
 (2,240,000) (16) 17
NGL (MBbls) – Forwards/Swaps(4,997) (45) 20
 (2,493) 5
 16
Crude (MBbls) – Forwards/Swaps35,280
 (190) 152
 9,172
 (4) 9
Refined Products (MBbls) – Futures(1,521) (5) 9
 (3,783) (25) 4
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
(21,475) (4) 
 (39,770) (2) 
Fixed Swaps/Futures(41,102,500) 5
 12
 (36,370,000) (26) 14
(21,475) (2) 7
 (39,770) 14
 11
(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 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.


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Interest Rate Risk
As of September 30, 20172018, we had $5.20$4.88 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $52$49 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


68


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:
Term 
Type(1)
 Notional Amount Outstanding 
Type(1)
 Notional Amount Outstanding
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
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
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate $
 $300
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
 Forward-starting to pay a fixed rate of 3.56% and receive a floating rate 400
 300
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
July 2021(2)
 Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400
 
December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
(1) 
Floating rates are based on 3-month LIBOR.  
(2) 
Represents the effective date. These forward-starting swaps have terms 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$239 million as of September 30, 2017.2018. For the $1.50 billion of interest rate swaps whereby we pay a floating rate and receive 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$4 million. 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 Chief 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 September 30, 20172018 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
As a result of the Sunoco Logistics Merger, which was completed in April 2017, our internal control over financial reporting now includes the controls of Energy Transfer, LP (formerly named “Energy Transfer Partners, L.P.”). The internal control over financial


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reporting of Energy Transfer, LP was evaluated by Energy Transfer, LP’s management (which is now the Partnership’s management) as of December 31, 2016 under the same framework that the Partnership’s internal control over financial reporting was evaluated, and Energy Transfer, LP’s management concluded that its internal control over financial reporting was effective as of December 31, 2016.
There have been no other changes in our internal controls 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 September 30, 20172018 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.


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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see Exhibit 99.3 to our CurrentAnnual Report on Form 8-K10-K filed with the SEC on May 8, 2017February 23, 2018 and Note 1110 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Partners,Operating, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2017.2018.
The EPA has brought aAdditionally, we have received notices of violations and potential fines under various federal, court action against SPLPstate and Mid-Valley for violationslocal provisions relating to the discharge of materials into the environment or protection of the Clean Water Act (“CWA”). The United States’ complaint allegesenvironment. While we believe that SPLP and Mid-Valley violated Sections 311(b)(7)(A) and 301(a)even if any one or more of the CWA when,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 three separate releases, pipelines operatedthe period covered by SPLP and ownedthis report, (ii) that became a reportable event during the period covered by SPLPthis report, or Mid-Valley Pipeline Company discharged oil. See 33 U.S.C. §§ 1311(a) and 1321(b)(7)(A). In particular,(iii) for which there has been a material development during 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) onperiod covered by this report.
On January 20, 2015, in Grant County, Oklahoma, when a reported 40 barrels of oil were discharged.  Potential fines from the DOJ are $7 million and from the State of Louisiana are approximately $1 million. The Partnership is currently in discussions to resolve these matters.
Mont Belvieu received18, 2018, PHMSA issued a Notice of EnforcementProbable Violation and a Proposed Compliance Order in connection with alleged violations on our Eastern Area refined products and crude oil pipeline system in the states of Michigan, Ohio, Pennsylvania, New York, New Jersey and Delaware.  We have paid the civil penalties of $163,700. The case was closed in July 2018.
In June 2018, ETC Northeast Pipeline LLC (“NOE”ETC Northeast”) entered into a Consent Order and Agreement with an Agreed Order from the Texas Commission on Environmental QualityPADEP, pursuant to which ETC Northeast agreed to pay $150,242 to the PADEP to settle various statutory and common law claims relating to soil discharge into, and erosion of the stream bed of, Raccoon Creek in Center Township, Pennsylvania during construction of the Revolution Pipeline. ETC Northeast has a pendingpaid the settlement for $0.01 million.  The NOE was foramount and continues to monitor the two violations.construction site and work with the landowner to resolve any remaining issues related to the restoration of the construction site.
On June 29, 2018, Luminant Energy Company, LLC (“Luminant”) filed informal and formal complaints against Energy Transfer CompanyFuel, LP (“ETF”), with the Railroad Commission of Texas (“TRRC”).  Luminant’s complaints allege that absent an agreement between Luminant and ETF regarding the rate to be charged for bundled transportation and storage service, ETF must file a statement of intent with the TRRC to change the rate charged to Luminant for this service.  ETF filed a response to Luminant’s informal complaint on July 16, 2018. ETF filed a response and motion to dismiss Luminant’s formal complaint on July 23, 2018. On August 16, 2018, a Commission Administrative Law Judge (“ALJ”) granted ETF’s motion to dismiss Luminant’s claims relating to unlawful abandonment and discrimination. The ALJ denied ETF’s motion to dismiss Luminant’s claims regarding the rate charged for service and the procedural process applicable to rate changes. Luminant appealed the decision. The appeal was denied by operation of law on October 1, 2018. A mediation of the informal complaint filed by Luminant was held on September 17, 2018 and no decision was reached. The parties continue to negotiate in good faith.
On July 25, 2018, Energy Transfer Field Services LLC received a settlement agreement and a stipulated final compliance order fromNOV REG-0569-1802 for emission events that occurred January 1, 2018 through April 30, 2018 at the Jal 3 gas plant. On September 25, 2018, the New Mexico Environmental Department (“NMED”) on October 12, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. This order is a combination of Notice of Violation REG-0569-1402-R1 and Notice of Violation REG-0569-1601. The alleged violations occurred during the periods of March 24, 2014 through September 30, 2014 and September 1, 2016 through December 31, 2016. The settlement includes a civil penalty in the amount of $0.4 million and a supplement environmental project in the amount of $0.8 million.
Energy Transfer Company Field Services, LLC receivedsent ETP a settlement offer fromto resolve the NMED on June 6, 2017NOV for allegationsa penalty of $1,151,499. Negotiations for this settlement offer are ongoing.
On September 17, 2018, William D. Warner (“Plaintiff”), a purported ETP unitholder, filed a putative class action asserting violations of New Mexico air regulations relatedvarious provisions of the Securities Exchange Act of 1934 and various rules promulgated thereunder in connection with the ETE-ETP Merger against ETP, Kelcy L. Warren, Michael K. Grimm, Marshall S. McCrea, Matthew S. Ramsey, David K. Skidmore, and W. Brett Smith (“Defendants”). Plaintiff specifically alleges that the Form S-4 Registration Statement issued in connection with the ETE-ETP Merger omits and/or misrepresents material information. Defendants believe the allegations have no merit and intend to Jal #3 facilities. The alleged violation occurred duringdefend vigorously against them. On October 26, 2018, Plaintiff and Defendants entered into a stipulation staying Defendants’ response deadlines until the perioddesignation of January 1, 2017 through September 11, 2017. The NMED is offering to settlea lead plaintiff/lead counsel structure in accordance with the violations with a civil penalty of $0.6 million.Private Securities Litigation Reform Act.
ITEM 1A. RISK FACTORS
There have been no material changes from the risk factors described in Part I, Item 1A in ourthe Partnership’s Annual Report on Form 10-K for our previous fiscalthe year ended December 31, 2016 and2017 filed with the SEC on February 23, 2018 or from the risk factors described in Exhibit 99.3 to our Current“Part II - Item 1A. Risk Factors” in the Partnership’s Quarterly Report on Form 8-K10-Q for the quarter ended March 31, 2018 filed with the SEC on May 8, 2017.10, 2018 and “Part II - Item 1A. Risk Factors” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed on August 9, 2018.


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ITEM 6. EXHIBITS
The exhibits listed below are filed or furnished, as indicated, as part of this report:
Exhibit Number Description
 
 
 
 
 
 
 
 
 
 
 
101.INS* XBRL Instance Document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Label Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
* Filed herewith.
** Furnished herewith.
***Denotes a management contract or compensatory plan or arrangement.


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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 PARTNERS,OPERATING, L.P.
    
  By:Energy Transfer Partners GP, L.P.,
   its General Partnergeneral partner
    
  By:Energy Transfer Partners, L.L.C.,
   its General Partnergeneral partner
    
Date:November 7, 20178, 2018By:/s/ A. Troy Sturrock
   A. Troy Sturrock
   
Senior Vice President, Controller and Principal Accounting Officer
(duly authorized to sign on behalf of the registrant)


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