ý
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2018
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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73-1493906
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(state or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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Title of each class
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Name of each exchange on which registered
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Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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New York Stock Exchange
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Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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New York Stock Exchange
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PAGE
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ITEM 1.
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ITEM 1A.
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ITEM 1B.
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ITEM 2.
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ITEM 3.
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ITEM 4.
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ITEM 5.
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ITEM 6.
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ITEM 7.
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ITEM 7A.
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ITEM 8.
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ITEM 9.
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ITEM 9A.
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ITEM 9B.
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ITEM 10.
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ITEM 11.
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ITEM 12.
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ITEM 13.
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ITEM 14.
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ITEM 15.
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ITEM 16.
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/d
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per day
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AOCI
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accumulated other comprehensive income (loss)
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AROs
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asset retirement obligations
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Bbls
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barrels
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BBtu
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billion British thermal units
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Bcf
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billion cubic feet
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Btu
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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
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Capacity
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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
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CDM
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CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively
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Citrus
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Citrus, LLC, which owns 100% of FGT
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CrossCountry
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CrossCountry Energy, LLC
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Dakota Access
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Dakota Access, LLC
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DOE
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United States Department of Energy
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DOJ
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United States Department of Justice
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DOT
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United States Department of Transportation
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EPA
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United States Environmental Protection Agency
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ET
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Energy Transfer LP, a publicly traded partnership and the owner of ETP LLC for the periods presented herein
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ETC FEP
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ETC Fayetteville Express Pipeline, LLC
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ETC MEP
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ETC Midcontinent Express Pipeline, L.L.C.
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ETC OLP
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La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
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ETC Tiger
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ETC Tiger Pipeline, LLC
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ETCO
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Energy Transfer Crude Oil Company, LLC
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ETP GP
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Energy Transfer Partners GP, L.P., the general partner of ETO
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ETP Holdco
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ETP Holdco Corporation
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ETP LLC
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Energy Transfer Partners, L.L.C., the general partner of ETP GP
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Exchange Act
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Securities Exchange Act of 1934, as amended
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ExxonMobil
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Exxon Mobil Corporation
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FEP
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Fayetteville Express Pipeline LLC
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FERC
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Federal Energy Regulatory Commission
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FGT
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Florida Gas Transmission Company, LLC
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GAAP
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accounting principles generally accepted in the United States of America
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Gulf States
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Gulf States Transmission LLC
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HPC
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RIGS Haynesville Partnership Co.
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IDRs
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incentive distribution rights
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KMI
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Kinder Morgan Inc.
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Lake Charles LNG
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Lake Charles LNG Company, LLC (previously named Trunkline LNG Company, LLC)
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LCL
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Lake Charles LNG Export Company, LLC
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LDEQ
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Louisiana Department of Environmental Quality
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LIBOR
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London Interbank Offered Rate
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LNG
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liquefied natural gas
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Lone Star
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Lone Star NGL LLC
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LPG
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liquefied petroleum gas
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MBbls
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thousand barrels
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MEP
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Midcontinent Express Pipeline LLC
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Mi Vida JV
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Mi Vida JV LLC
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Mid-Valley
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Mid-Valley Pipeline Company
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MMcf
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million cubic feet
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MTBE
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methyl tertiary butyl ether
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NGL
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natural gas liquid, such as propane, butane and natural gasoline
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NYMEX
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New York Mercantile Exchange
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NYSE
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New York Stock Exchange
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ORS
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Ohio River System LLC
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OSHA
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federal Occupational Safety and Health Act
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OTC
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over-the-counter
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Panhandle
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Panhandle Eastern Pipe Line Company, LP and its subsidiaries
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PCBs
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polychlorinated biphenyls
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PennTex
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PennTex Midstream Partners, LP
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PEP
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Permian Express Partners LLC
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PES
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Philadelphia Energy Solutions Refining and Marketing LLC
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Phillips 66
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Phillips 66 Partners LP
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PHMSA
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Pipeline Hazardous Materials Safety Administration
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Ranch JV
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Ranch Westex JV LLC
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Regency
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Regency Energy Partners LP
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Retail Holdings
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ETP Retail Holdings, LLC, a subsidiary of ETO
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RIGS
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Regency Intrastate Gas System
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Rover
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Rover Pipeline LLC, a subsidiary of ETO
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Sea Robin
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Sea Robin Pipeline Company, LLC, a subsidiary of Panhandle
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SEC
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Securities and Exchange Commission
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Series A Preferred Units
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6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Series B Preferred Units
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6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Series C Preferred Units
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7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Series D Preferred Units
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7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Shell
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Royal Dutch Shell plc
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SPLP
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Sunoco Pipeline L.P.
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Sunoco GP
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Sunoco GP LLC, the general partner of Sunoco LP
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Sunoco Logistics
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Sunoco Logistics Partners L.P.
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Sunoco Partners
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Sunoco Partners LLC, the general partner of Sunoco Logistics
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Transwestern
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Transwestern Pipeline Company, LLC
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TRRC
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Texas Railroad Commission
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Trunkline
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Trunkline Gas Company, LLC, a subsidiary of Panhandle
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USAC
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USA Compression Partners, LP
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•
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natural gas operations, including the following:
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natural gas midstream and intrastate transportation and storage;
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interstate natural gas transportation and storage; and
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•
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crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.
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•
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In October 2018, ET and ETO (previously named Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P., respectively, prior to the October 2018 transactions) completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). Immediately prior to the Energy Transfer Merger, (i) the IDRs in ETO were converted into ETO Common Units, (ii) the general partner interest in ETO was converted into ETO Common Units, (iii) ET’s interests in Sunoco LP, USAC and their respective general partners were contributed to ETO, and (iv) certain other
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In April 2018,
ETO 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
USAC common units, (ii)
6,397,965
units of a new 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 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.
ETO subsequently obtained control of USAC in connection with the transactions related to the Energy Transfer Merger in October 2018, as discussed above.
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ETO
previously owned a
49.99%
interest in HPC, which owns RIGS
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In April 2018, ETO acquired the remaining
50.01%
interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in ETO’s financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in ETO’s financial statements.
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On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”), and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven. Under the agreement, Sunoco LP sold a portfolio of approximately
1,030
company-operated retail fuel outlets in
19
geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of
$3.2 billion
.
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•
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In September 2018, ETO, 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 transaction structure for this project has not been finalized.
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In August 2018, the Partnership received approval to commence service on 100% of the long-haul contractual commitments on Rover to begin September 1, 2018, and on November 2, 2018, the Partnership announced that it received approval to commence service on the final laterals needed to complete the Rover pipeline project.
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In March 2018, ETO and 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 its ethane cracking facilities in China.
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approximately
4,769
miles of NGL pipelines
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NGL and propane fractionation facilities with an aggregate capacity of
825 MBbls/d
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NGL storage facility in Mont Belvieu with a working storage capacity of approximately
45 million Bbls
; and
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other NGL storage assets, located at our Cedar Bayou and Hattiesburg storage facilities, and our Nederland, Marcus Hook and Inkster NGL terminals with an aggregate storage capacity of approximately
11 million Bbls
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purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;
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storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);
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buying and selling crude oil of different grades, at different locations in order to maximize value;
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transporting crude oil using the pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and
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marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
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Our approximately
8%
non-operating interest in PES, which owns a refinery in Philadelphia.
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Our marketing operations in which we market the natural gas that flows through our gathering and intrastate transportation assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation. For the off-system gas, we purchase gas or act as an agent for small independent producers that may not have marketing operations.
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Our natural gas compression equipment business which has operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.
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Our wholly-owned subsidiary, Dual Drive Technologies, Ltd. (“DDT”), which provides compression services to customers engaged in the transportation of natural gas, including our other segments.
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Our subsidiaries are involved in 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.
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PEI Power LLC and PEI Power II, which own and operate a facility in Pennsylvania that generates a total of
75
megawatts of electrical power.
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Description of Assets
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Ownership Interest
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Miles of Natural Gas Pipeline
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Pipeline Throughput Capacity
(Bcf/d)
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Working Storage Capacity
(Bcf/d)
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ET Fuel System
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100
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%
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3,150
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5.2
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11.2
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Oasis Pipeline
(1)
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100
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%
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750
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2.0
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—
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HPL System
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100
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%
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3,920
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5.3
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52.5
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ETC Katy Pipeline
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100
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%
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460
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2.4
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—
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Regency Intrastate Gas
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100
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%
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450
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2.1
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—
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Comanche Trail Pipeline
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16
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%
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195
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1.1
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—
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Trans-Pecos Pipeline
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16
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%
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143
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1.4
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—
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Old Ocean Pipeline, LLC
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50
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%
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240
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0.2
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—
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Red Bluff Express Pipeline
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70
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%
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100
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1.4
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—
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(1)
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Includes bi-directional capabilities
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•
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The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines
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The Oasis Pipeline is primarily a
36-inch
natural gas pipeline. It has bi-directional capabilities with approximately
1.3 Bcf/d
of throughput capacity moving west-to-east and greater than
750 MMcf/d
of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
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•
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The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Beaumont and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing us to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel, Carthage and Agua Dulce, as well as our Bammel storage facility.
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•
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The ETC Katy Pipeline connects three treating facilities, one of which we own, with our gathering system known as Southeast Texas System. The ETC Katy pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The ETC Katy pipeline expansions include the 36-inch East Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL System.
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•
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RIGS is a
450
-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets.
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•
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Comanche Trail is a
195
-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a
16%
membership interest in and operates Comanche Trail.
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•
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Trans-Pecos is a
143
-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a
16%
membership interest in and operates Trans-Pecos.
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•
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Old Ocean is a
240
-mile intrastate pipeline system that delivers natural gas from Ellis County, Texas to Brazoria County, Texas. The Partnership owns a
50%
membership interest in and operates Old Ocean.
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•
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The Red Bluff Express Pipeline is an approximately
100
-mile intrastate pipeline that runs through the heart of the Delaware basin and connects our Orla Plant, as well as third-party plants to the Waha Oasis Header. An expansion of the Red Bluff Express Pipeline is expected to be in service in the second half of 2019. The Partnership owns a
70%
membership interest in and operates Red Bluff Express.
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Description of Assets
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Ownership Interest
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Miles of Natural Gas Pipeline
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Pipeline Throughput Capacity
(Bcf/d)
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Working Gas Capacity
(Bcf/d)
|
||||
Florida Gas Transmission
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50
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%
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5,344
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3.4
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—
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Transwestern Pipeline
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100
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%
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2,614
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2.1
|
|
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—
|
|
Panhandle Eastern Pipe Line
(1)
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100
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%
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6,402
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|
|
2.8
|
|
|
73.4
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|
Trunkline Gas Company
|
|
100
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%
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|
2,231
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|
|
0.9
|
|
|
13.0
|
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Tiger Pipeline
|
|
100
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%
|
|
197
|
|
|
2.4
|
|
|
—
|
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Fayetteville Express Pipeline
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50
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%
|
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185
|
|
|
2.0
|
|
|
—
|
|
Sea Robin Pipeline
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100
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%
|
|
785
|
|
|
2.0
|
|
|
—
|
|
Rover Pipeline
|
|
32.6
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%
|
|
713
|
|
|
3.25
|
|
|
—
|
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Midcontinent Express Pipeline
|
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50
|
%
|
|
512
|
|
|
1.8
|
|
|
—
|
|
Gulf States
|
|
100
|
%
|
|
10
|
|
|
0.1
|
|
|
—
|
|
(1)
|
Natural gas storage assets are owned by Pan Gas Storage LLC (d.b.a Southwest Gas Storage Company).
|
•
|
Florida Gas Transmission Pipeline (“FGT”) has mainline capacity of
3.4 Bcf/d
and approximately
5,344
miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over
60%
of the natural gas consumed in the state. In addition, FGT’s system operates and maintains multiple interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrial end-users and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture with KMI.
|
•
|
Transwestern Pipeline transports natural gas supply from the Permian Basin in West Texas and eastern New Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado, and the Anadarko Basin in the Texas and Oklahoma panhandles. The system has bi-directional capabilities and can access Texas and midcontinent connecting pipelines and natural gas market hubs, as well as major western markets in Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
|
•
|
Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately
1,300 miles
from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. Panhandle contracts for over
73
Bcf of natural gas storage.
|
•
|
Trunkline Gas Company’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately
1,400 miles
from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan. Trunkline has one natural gas storage field located in Louisiana.
|
•
|
Tiger Pipeline is a bi-directional system that extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to multiple interstate pipelines.
|
•
|
Fayetteville Express Pipeline originates near Conway County, Arkansas and continues eastward to Panola County, Mississippi with multiple pipeline interconnections along the route. Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.
|
•
|
Sea Robin Pipeline’s system consists of two offshore Louisiana natural gas supply pipelines extending
120 miles
into the Gulf of Mexico.
|
•
|
Rover Pipeline is a large diameter pipeline with total capacity to transport
3.25
Bcf/d natural gas from processing plants in West Virginia, Eastern Ohio and Western Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the gas is delivered for distribution to markets across the United States, as well as to Ontario, Canada.
|
•
|
Midcontinent Express Pipeline originates near Bennington, Oklahoma and traverses northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline system in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI, the operator of the system.
|
•
|
Gulf States Transmission is a
10
-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
|
Description of Assets
|
|
Net Gas Processing Capacity
(MMcf/d)
|
|
South Texas Region:
|
|
|
|
Southeast Texas System
|
|
410
|
|
Eagle Ford System
|
|
1,920
|
|
Ark-La-Tex Region
|
|
1,442
|
|
North Central Texas Region
|
|
700
|
|
Permian Region
|
|
2,340
|
|
Midcontinent Region
|
|
860
|
|
Eastern Region
|
|
200
|
|
•
|
The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the ETC Katy Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plants (La Grange and Alamo) with aggregate capacity of
410 MMcf/d
. The La Grange and Alamo processing plants are natural gas processing plants that process the rich gas that flows through our gathering system to produce residue
|
•
|
The Eagle Ford Gathering System consists of
30-inch
and
42-inch
natural gas gathering pipelines with over
1.4 Bcf/d
of capacity originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of
1.92
Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines for delivery of NGLs to Lone Star.
|
•
|
Our Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger Pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of
870
MMcf/d.
|
•
|
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the ten natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Brookeland, Lincoln Parish and Mt. Olive) have an aggregate capacity of
1.3
Bcf/d.
|
•
|
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, as well as other pipelines, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
|
•
|
The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. Our North Central Texas assets include our Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of
700 MMcf/d
. The Godley plant is integrated with the ET Fuel System.
|
•
|
The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the midcontinent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes eleven processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther, Rebel and Arrowhead) with an aggregate processing capacity of
2.02
Bcf/d and one natural gas conditioning facility with aggregate capacity of
200 MMcf/d
.
|
•
|
We own a
50%
membership interest in Mi Vida JV, a joint venture which owns a
200 MMcf/d
cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of Mi Vida JV.
|
•
|
We own a
50%
membership interest in Ranch JV, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a
25 MMcf/d
refrigeration plant and a
125 MMcf/d
cryogenic processing plant.
|
•
|
The Midcontinent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include fourteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray and Gray) with an aggregate capacity of
860 MMcf/d
.
|
•
|
We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
|
•
|
We also own the Hugoton Gathering System that has
1,900
miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
|
•
|
The Eastern Region assets are located in eleven counties in Pennsylvania, four counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. Our Eastern Region assets include approximately
600
miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems, as well as the
200 MMcf/d
Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.
|
•
|
We also own a
51%
membership interest in Aqua – ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
|
•
|
We own a
75%
membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of
47 miles
of 36-inch,
13 miles
of
30-inch
and
3 miles
of
24-inch
gathering trunklines, that delivers up to
3.6 Bcf/d
to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18.
|
Description of Assets
|
|
Miles of Liquids Pipeline
(2)
|
|
Pipeline Throughput Capacity
(MBbls/d)
|
|
NGL Fractionation / Processing Capacity
(MBbls/d)
|
|
Working Storage Capacity
(MBbls)
|
||||
Liquids Pipelines:
|
|
|
|
|
|
|
|
|
||||
Lone Star Express
|
|
535
|
|
|
507
|
|
|
—
|
|
|
—
|
|
West Texas Gateway Pipeline
|
|
512
|
|
|
240
|
|
|
—
|
|
|
—
|
|
Lone Star
|
|
1,617
|
|
|
120
|
|
|
—
|
|
|
—
|
|
Mariner East
|
|
670
|
|
|
345
|
|
|
—
|
|
|
—
|
|
Mariner South
|
|
97
|
|
|
200
|
|
|
—
|
|
|
—
|
|
Mariner West
|
|
395
|
|
|
50
|
|
|
—
|
|
|
—
|
|
Other NGL Pipelines
|
|
943
|
|
|
591
|
|
|
—
|
|
|
—
|
|
Liquids Fractionation and Services Facilities:
|
|
|
|
|
|
|
|
|
||||
Mont Belvieu Facilities
|
|
163
|
|
|
42
|
|
|
790
|
|
|
45,500
|
|
Sea Robin Processing Plant
(1)
|
|
—
|
|
|
—
|
|
|
26
|
|
|
—
|
|
Refinery Services
(1)
|
|
103
|
|
|
—
|
|
|
35
|
|
|
—
|
|
Hattiesburg Storage Facilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,000
|
|
Cedar Bayou
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,600
|
|
NGL Terminals:
|
|
|
|
|
|
|
|
|
||||
Nederland
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,200
|
|
Marcus Hook Industrial Complex
|
|
—
|
|
|
—
|
|
|
132
|
|
|
5,000
|
|
Inkster
|
|
—
|
|
|
—
|
|
|
—
|
|
|
800
|
|
Refined Products Pipelines
|
|
2,203
|
|
|
800
|
|
|
—
|
|
|
—
|
|
Refined Products Terminals:
|
|
|
|
|
|
|
|
|
||||
Eagle Point
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,000
|
|
Marcus Hook Industrial Complex
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,000
|
|
Marcus Hook Tank Farm
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,000
|
|
Marketing Terminals
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,000
|
|
(1)
|
Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of
850 MMcf/d
and
54 MMcf/d
, respectively.
|
(2)
|
Miles of pipeline as reported to PHMSA.
|
•
|
The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility. An expansion of the pipeline is currently underway, which will add approximately
400
MBbls/d of NGL pipeline capacity from Lone Star’s pipeline system near Wink, Texas to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas. It is expected to be in service by the fourth quarter of 2020.
|
•
|
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.
|
•
|
The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, began service in December 2018.
|
•
|
The Mariner South liquids pipeline delivers export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas.
|
•
|
The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border.
|
•
|
Refined products pipelines include approximately
2,203
miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. These operations include our controlling financial interest in Inland Corporation (“Inland”). The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
|
•
|
Other NGL pipelines include the
127-mile
Justice pipeline with capacity of
375 MBbls/d
, the
45-mile
Freedom pipeline with a capacity of
56 MBbls/d
, the
20-mile
Spirit pipeline with a capacity of
20 MBbls/d
and a
50%
interest in the
87-mile
Liberty pipeline with a capacity of
140 MBbls/d
.
|
•
|
Our Mont Belvieu storage facility is an integrated liquids storage facility with over
46 million Bbls
of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
|
•
|
Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator VI was placed in service in February 2019, Fractionator VII is currently under construction and is scheduled to be operational by the first quarter of 2020.
|
•
|
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.
|
•
|
Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately
103
miles of pipeline to the Chalmette processing plant, which has a processing capacity of
54 MMcf/d
.
|
•
|
The Hattiesburg storage facility is an integrated liquids storage facility with approximately
3 million Bbls
of salt dome capacity, providing 100% fee-based cash flows.
|
•
|
The Cedar Bayou storage facility is an integrated liquids storage facility with approximately
1.6 million Bbls
of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.
|
•
|
The Nederland terminal, in addition to crude oil activities, also provides approximately
1 million Bbls
of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be exported via ship.
|
•
|
The Marcus Hook Industrial Complex includes fractionation, terminalling and storage assets, with a capacity of approximately
2 million
Bbls of NGL storage capacity in underground caverns,
3 million
Bbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately
1 million Bbls
. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for our Mariner East 1 pipeline system.
|
•
|
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately
800
MBbls of NGLs. We use the Inkster terminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
|
•
|
We have approximately
35
refined products terminals with an aggregate storage capacity of approximately
8 million
Bbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.
|
•
|
In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately
6 million Bbls
, and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
|
•
|
The Marcus Hook Tank Farm has a total refined products storage capacity of approximately
2 million Bbls
of refined products storage. The tank farm historically served ETC Sunoco Holdings LLC (“Sunoco Inc.’s”) Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.’s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on our refined products pipelines.
|
•
|
The Eastern refined products pipelines consists of approximately 561 miles of 6-inch to 24-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, approximately 162 miles of 8-inch refined products pipeline in western New York and approximately 183 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
|
•
|
The midcontinent refined products pipelines primarily consists of approximately 294 miles of 3-inch to 12-inch refined products pipelines in Ohio, approximately 85 miles of 6-inch to 12-inch refined products pipeline in Western Pennsylvania and approximately 52 miles of 8-inch refined products pipeline in Michigan.
|
•
|
The Southwest refined products pipelines is located in Eastern Texas and consists primarily of approximately 375 miles of 8-inch diameter refined products pipeline.
|
•
|
The Inland refined products pipeline, approximately 486 miles of pipeline in Ohio, consists of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 135 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 53 miles of 8-inch diameter refined products pipeline in western Ohio and the remaining refined products pipeline primarily consists of 5 and 6-inch diameter pipeline in Northeast Ohio.
|
•
|
This segment also includes the following joint ventures: 15% membership interest in the Explorer Pipeline Company, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur, and Houston, Texas and extends to Chicago, Illinois; 31% membership interest in the Wolverine Pipe Line Company, a 700-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; and a 14% membership interest in the Yellowstone Pipe Line Company, a 700-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.
|
Description of Assets
|
|
Ownership Interest
|
|
Miles of Crude Pipeline
(1)
|
|
Working Storage Capacity
(MBbls) |
|||
Dakota Access Pipeline
|
|
36.4
|
%
|
|
1,158
|
|
|
—
|
|
Energy Transfer Crude Oil Pipeline
|
|
36.4
|
%
|
|
760
|
|
|
—
|
|
Bayou Bridge Pipeline
|
|
60
|
%
|
|
49
|
|
|
—
|
|
Permian Express Pipelines
|
|
87.7
|
%
|
|
1,712
|
|
|
—
|
|
Other Crude Oil Pipelines
|
|
100
|
%
|
|
5,845
|
|
|
—
|
|
Nederland Terminal
|
|
100
|
%
|
|
—
|
|
|
28,000
|
|
Fort Mifflin Terminal
|
|
100
|
%
|
|
—
|
|
|
3,570
|
|
Eagle Point Terminal
|
|
100
|
%
|
|
—
|
|
|
1,000
|
|
Midland Terminal
|
|
100
|
%
|
|
—
|
|
|
2,000
|
|
Marcus Hook Industrial Complex
|
|
100
|
%
|
|
—
|
|
|
1,000
|
|
Patoka, Illinois Terminal
|
|
87.7
|
%
|
|
—
|
|
|
2,000
|
|
(1)
|
Miles of pipeline as reported to PHMSA.
|
•
|
Bakken Pipeline.
Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a
1,918
mile pipeline with capacity of
570
MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including our crude terminal in Nederland Texas.
|
•
|
Bayou Bridge Pipeline.
The Bayou Bridge Pipeline is a joint venture between ETO and Phillips 66, in which ETO has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, with commercial operations expected to begin in March 2019.
|
•
|
Permian Express Pipelines.
The Permian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Express 3, which became fully operational in September 2018, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Nederland Access pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, which origins in multiple locations in Western Texas.
|
•
|
Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
|
•
|
Nederland.
The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has a total storage capacity of approximately
28 million
Bbls in approximately 150 above ground storage tanks with individual capacities of up to
660 MBbls
.
|
•
|
Fort Mifflin.
The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin terminal complex by charging fees based on throughput.
|
•
|
Eagle Point.
The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately
1 million
Bbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
|
•
|
Midland.
The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately
2 million
Bbls of crude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.
|
•
|
Marcus Hook Industrial Complex.
The Marcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately
1 million
Bbls.
|
•
|
Patoka, Illinois Terminal.
The Patoka, Illinois terminal is a tank farm and was contributed by ExxonMobil to the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 2 million Bbls of crude oil storage.
|
•
|
Sunoco, LLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in
30
states throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama, Texas, Arkansas and New York;
|
•
|
Sunoco Retail LLC (“Sunoco Retail”), a Pennsylvania limited liability company, owns and operates retail stores that sell motor fuel and merchandise primarily in New Jersey;
|
•
|
Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands; and
|
•
|
Aloha Petroleum, Ltd. (“Aloha”), a Hawaii corporation, owns and operates retail stores on the Hawaiian Islands.
|
•
|
75
company owned and operated retail stores;
|
•
|
554
independently operated consignment locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;
|
•
|
6,741
convenience stores and retail fuel outlets operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and
|
•
|
2,714
other commercial customers, including unbranded convenience stores, other fuel distributors, school districts and municipalities and other industrial customers.
|
Unit Horsepower
|
|
Fleet Horsepower
|
|
Number of Units
|
|
Horsepower on Order
(1)
|
|
Number of Units on Order
|
|
Total Horsepower
|
|
Total Number of Units
|
||||||
Small horsepower
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
<400
|
|
528,084
|
|
|
3,101
|
|
|
900
|
|
|
4
|
|
|
528,984
|
|
|
3,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Large horsepower
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
>400 and <1,000
|
|
429,203
|
|
|
735
|
|
|
—
|
|
|
—
|
|
|
429,203
|
|
|
735
|
|
>1,000
|
|
2,639,810
|
|
|
1,650
|
|
|
130,850
|
|
|
55
|
|
|
2,770,660
|
|
|
1,705
|
|
Total large horsepower
|
|
3,069,013
|
|
|
2,385
|
|
|
130,850
|
|
|
55
|
|
|
3,199,863
|
|
|
2,440
|
|
Total horsepower
|
|
3,597,097
|
|
|
5,486
|
|
|
131,750
|
|
|
59
|
|
|
3,728,847
|
|
|
5,545
|
|
(1)
|
As of
December 31, 2018
, USAC had
131,750
horsepower on order for delivery during
2019
.
|
•
|
approve the siting, construction and operation of new facilities;
|
•
|
review and approve transportation rates;
|
•
|
determine the types of services our regulated assets are permitted to perform;
|
•
|
regulate the terms and conditions associated with these services;
|
•
|
permit the extension or abandonment of services and facilities;
|
•
|
require the maintenance of accounts and records; and
|
•
|
authorize the acquisition and disposition of facilities.
|
•
|
the amount of natural gas, NGLs, crude oil and refined products transported in our pipelines;
|
•
|
the level of throughput in our processing and treating operations;
|
•
|
the fees we charge and the margins we realize for our services;
|
•
|
the price of natural gas, NGLs, crude oil and refined products;
|
•
|
the relationship between natural gas, NGL and crude oil prices;
|
•
|
the weather in our operating areas;
|
•
|
the level of competition from other midstream, transportation and storage and other energy providers;
|
•
|
the level of our operating costs;
|
•
|
prevailing economic conditions; and
|
•
|
the level and results of our derivative activities.
|
•
|
the level of capital expenditures we make;
|
•
|
the level of costs related to litigation and regulatory compliance matters;
|
•
|
the cost of acquisitions, if any;
|
•
|
the levels of any margin calls that result from changes in commodity prices;
|
•
|
our debt service requirements;
|
•
|
fluctuations in our working capital needs;
|
•
|
our ability to borrow under our revolving credit facility;
|
•
|
our ability to access capital markets;
|
•
|
restrictions on distributions contained in our debt agreements; and
|
•
|
the amount of cash reserves established by our General Partner in its discretion for the proper conduct of our business.
|
•
|
Unitholders’ current proportionate ownership interest in each partnership will decrease;
|
•
|
the amount of cash available for distribution on each common unit or partnership security may decrease;
|
•
|
the ratio of taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding common unit may be diminished; and
|
•
|
the market price of each partnership’s common units may decline.
|
•
|
a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;
|
•
|
covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;
|
•
|
our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
|
•
|
we may be at a competitive disadvantage relative to similar companies that have less debt;
|
•
|
we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and
|
•
|
failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.
|
•
|
the right to share in the Partnership’s profits and losses;
|
•
|
the right to share in the Partnership’s distributions;
|
•
|
the rights upon dissolution and liquidation of the Partnership;
|
•
|
whether, and the terms upon which, the Partnership may redeem the securities;
|
•
|
whether the securities will be issued, evidenced by certificates and assigned or transferred; and
|
•
|
the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.
|
•
|
to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);
|
•
|
to provide funds for distributions to our preferred unitholders; or
|
•
|
to comply with applicable law or any of our loan or other agreements.
|
•
|
economic downturns;
|
•
|
deteriorating capital market conditions;
|
•
|
declining market prices for natural gas, NGLs and other commodities;
|
•
|
terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
|
•
|
the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
|
•
|
the allocation of shared overhead expenses to Sunoco LP, USAC and us;
|
•
|
the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Sunoco LP and USAC, on the other hand;
|
•
|
the determination of the amount of cash to be distributed to Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of Sunoco LP’s and USAC’s businesses;
|
•
|
the determination whether to make borrowings under Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners;
|
•
|
the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of Sunoco LP and USAC is made available for Sunoco LP and USAC to pursue; and
|
•
|
any decision we make in the future to engage in business activities independent of Sunoco LP and USAC.
|
•
|
our General Partner is allowed to take into account the interests of parties other than us, including Sunoco LP and USAC, and their respective affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.
|
•
|
our General Partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
|
•
|
our General Partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.
|
•
|
our General Partner determines which costs it and its affiliates have incurred are reimbursable by us.
|
•
|
our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.
|
•
|
our General Partner controls the enforcement of obligations owed to us by it and its affiliates.
|
•
|
our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
|
•
|
eliminates all standards of care and duties other than those set forth in our partnership agreement, including fiduciary duties, to the fullest extent permitted by law;
|
•
|
permits our General Partner to make a number of decisions in its “sole discretion,” which standard entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
|
•
|
provides that our General Partner is entitled to make other decisions in its “reasonable discretion;”
|
•
|
generally provides that affiliated transactions and resolutions of conflicts of interest must be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the interests of all parties involved, including its own;
|
•
|
provides that unless our General Partner has acted in bad faith, the action taken by our General Partner shall not constitute a breach of its fiduciary duty;
|
•
|
provides that our General Partner may resolve any conflicts of interest involving us and our General Partner and its affiliates, and any resolution of a conflict of interest by our General Partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the partnership agreement;
|
•
|
provides that our General Partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the General Partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us;
|
•
|
provides that our General Partner may consult with consultants and advisors and, subject to certain restrictions, is conclusively deemed to have acted in good faith when it acts in reliance on the opinion of such consultants and advisors; and
|
•
|
provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our General Partner and those other persons acted in good faith.
|
•
|
our partnership agreement limits the liability and reduces the fiduciary duties of our General Partner while also restricting the remedies available to our Unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law. Our General Partner is allowed to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duties to us.
|
•
|
our General Partner is allowed to take into account the interests of parties in addition to us, including ET, in resolving conflicts of interest, thereby limiting its fiduciary duties to us.
|
•
|
our General Partner’s affiliates, including ET, are not prohibited from engaging in other businesses or activities, including those in direct competition with us.
|
•
|
our General Partner determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings, repayments of debt, issuances of equity and debt securities and cash reserves, each of which can affect the amount of cash that is distributed to Unitholders and to ET.
|
•
|
neither our partnership agreement nor any other agreement requires ET or its affiliates to pursue a business strategy that favors us. The directors and officers of the general partners of ET have a fiduciary duty to make decisions in the best interest of their members, limited partners and Unitholders, which may be contrary to our best interests.
|
•
|
some of the directors and officers of ET who provide advice to us also may devote significant time to the businesses of ET and will be compensated by them for their services.
|
•
|
our General Partner determines which costs, including allocated overhead costs, are reimbursable by us.
|
•
|
our General Partner is allowed to resolve any conflicts of interest involving us and our General Partner and its affiliates, and any resolution of a conflict of interest by our General Partner that is fair and reasonable to us will be deemed approved by all partners and will not constitute a breach of the partnership agreement.
|
•
|
our General Partner controls the enforcement of obligations owed to us by it.
|
•
|
our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
|
•
|
our General Partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.
|
•
|
our General Partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us.
|
•
|
in some instances, our General Partner may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions.
|
•
|
the level of domestic natural gas, NGL, and oil production;
|
•
|
the level of natural gas, NGL, and oil imports and exports, including liquefied natural gas;
|
•
|
actions taken by natural gas and oil producing nations;
|
•
|
instability or other events affecting natural gas and oil producing nations;
|
•
|
the impact of weather and other events of nature on the demand for natural gas, NGLs and oil;
|
•
|
the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;
|
•
|
the price, availability and marketing of competitive fuels;
|
•
|
the demand for electricity;
|
•
|
activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;
|
•
|
the cost of capital needed to maintain or increase production levels and to construct and expand facilities
|
•
|
the impact of energy conservation and fuel efficiency efforts; and
|
•
|
the extent of governmental regulation, taxation, fees and duties.
|
•
|
the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;
|
•
|
the dependence on third parties to supply their fuel storage terminals;
|
•
|
outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;
|
•
|
the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;
|
•
|
the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;
|
•
|
the effects of a sustained recession or other adverse economic conditions;
|
•
|
the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products;
|
•
|
competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and
|
•
|
climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.
|
•
|
because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
|
•
|
because we are unable to raise financing for such acquisitions on economically acceptable terms; or
|
•
|
because we are outbid by competitors, some of which are substantially larger than us and have greater financial resources and lower costs of capital then we do.
|
•
|
fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
|
•
|
decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
|
•
|
significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;
|
•
|
encounter difficulties operating in new geographic areas or new lines of business;
|
•
|
incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;
|
•
|
be unable to hire, train or retrain qualified personnel to manage and operate our growing business and assets;
|
•
|
less effectively manage our historical assets, due to the diversion of management’s attention from other business concerns; or
|
•
|
incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
|
•
|
operating a larger combined organization in new geographic areas and new lines of business;
|
•
|
hiring, training or retaining qualified personnel to manage and operate our growing business and assets;
|
•
|
integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;
|
•
|
diversion of management’s attention from our existing business;
|
•
|
assimilation of acquired assets and operations, including additional regulatory programs;
|
•
|
loss of customers or key employees;
|
•
|
maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and
|
•
|
integrating new technology systems for financial reporting.
|
•
|
we are unable to identify pipeline construction opportunities with favorable projected financial returns;
|
•
|
we are unable to obtain necessary governmental approvals and contracts with qualified contractors and vendors on acceptable terms;
|
•
|
we are unable to raise financing for our identified pipeline construction opportunities; or
|
•
|
we are unable to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.
|
•
|
terms and conditions of service;
|
•
|
the types of services interstate pipelines may or must offer their customers;
|
•
|
construction of new facilities;
|
•
|
acquisition, extension or abandonment of services or facilities;
|
•
|
reporting and information posting requirements;
|
•
|
accounts and records; and
|
•
|
relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
|
•
|
perform ongoing assessments of pipeline integrity;
|
•
|
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
|
•
|
improve data collection, integration and analysis;
|
•
|
repair and remediate the pipeline as necessary; and
|
•
|
implement preventive and mitigating actions.
|
•
|
Less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:
|
•
|
provide for the proper conduct of our business (including reserves for future capital expenditures and for our future capital needs);
|
•
|
comply with applicable law and/or debt instrument or other agreement; or
|
•
|
provide funds for distributions to the Series A, Series B, Series C and Series D Preferred Unitholders.
|
•
|
Plus all cash on hand on the date of determination of Available Cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facilities and in all cases used solely for working capital purposes or to pay distributions to partners.
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
54,087
|
|
|
$
|
40,523
|
|
|
$
|
31,792
|
|
|
$
|
36,096
|
|
|
$
|
54,435
|
|
Operating income
|
5,402
|
|
|
2,765
|
|
|
1,975
|
|
|
2,341
|
|
|
2,461
|
|
|||||
Income from continuing operations
|
4,039
|
|
|
2,952
|
|
|
911
|
|
|
1,371
|
|
|
1,289
|
|
|||||
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
||||||||||
Assets held for sale
|
—
|
|
|
3,313
|
|
|
3,588
|
|
|
3,681
|
|
|
3,372
|
|
|||||
Total assets
(1)
|
88,442
|
|
|
86,484
|
|
|
78,984
|
|
|
71,117
|
|
|
63,928
|
|
|||||
Liabilities associated with assets held for sale
|
—
|
|
|
75
|
|
|
48
|
|
|
42
|
|
|
47
|
|
|||||
Long-term debt, less current maturities
|
37,853
|
|
|
36,971
|
|
|
36,251
|
|
|
30,505
|
|
|
24,831
|
|
|||||
Total equity
|
36,621
|
|
|
36,967
|
|
|
28,938
|
|
|
29,968
|
|
|
26,732
|
|
|||||
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
||||||||||
Maintenance (accrual basis)
(2)
|
510
|
|
|
479
|
|
|
474
|
|
|
550
|
|
|
449
|
|
|||||
Growth (accrual basis)
(2)
|
5,120
|
|
|
5,601
|
|
|
5,775
|
|
|
8,046
|
|
|
5,218
|
|
|||||
Cash paid for acquisitions
|
429
|
|
|
583
|
|
|
1,398
|
|
|
964
|
|
|
2,367
|
|
(1)
|
Includes assets held for sale
|
(2)
|
Maintenance and growth capital expenditures include Sunoco LP’s capital expenditures related to discontinued operations.
|
•
|
natural gas operations, including the following:
|
•
|
natural gas midstream and intrastate transportation and storage;
|
•
|
interstate natural gas transportation and storage; and
|
•
|
crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.
|
•
|
the IDRs in ETO were converted into
1,168,205,710
ETO common units; and
|
•
|
the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued
18,448,341
ETO common units to ETP GP.
|
•
|
2,263,158
common units representing limited partner interests in Sunoco LP to ETO in exchange for
2,874,275
ETO 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 ETO in exchange for
42,812,389
ETO 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 ETO in exchange for
16,134,903
ETO 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 ETO in exchange for
37,557,815
ETO common units.
|
•
|
Intrastate transportation and storage – Revenue is principally generated from fees charged to customers to reserve firm capacity on or move gas through our pipelines on an interruptible basis. Our interruptible or short-term business is generally impacted by basis differentials between delivery points on our system and the price of natural gas. The basis differentials that primarily impact our interruptible business are primarily among receipt points between West Texas to East Texas or segments thereof. When narrow or flat spreads exist, our open capacity may be underutilized and go unsold. Conversely, when basis differentials widen, our interruptible volumes and fees generally increase. The fee structure normally consists of a monetary fee and fuel retention. Excess fuel retained after consumption, if any, is typically sold at market prices. In addition to transport fees, we generate revenue from purchasing natural gas and transporting it across our system. The natural gas is then sold to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies. The HPL System purchases natural gas at the wellhead for transport and selling. Other pipelines with access to West Texas supply,
|
•
|
Interstate transportation and storage – The majority of our interstate transportation and storage revenues are generated through firm reservation charges that are based on the amount of firm capacity reserved for our firm shippers regardless of usage. Tiger, FEP, Transwestern, Panhandle, MEP and Gulf States shippers have made long-term commitments to pay reservation charges for the firm capacity reserved for their use. In addition to reservation revenues, additional revenue sources include interruptible transportation charges as well as usage rates and overrun rates paid by firm shippers based on their actual capacity usage.
|
•
|
Midstream – Revenue is principally dependent upon the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipelines as well as the level of natural gas and NGL prices.
|
•
|
NGL and refined products transportation and services – Liquids transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have
|
•
|
Crude oil transportation and services – Revenues are generated by charging tariffs for transporting crude oil though our pipelines as well as by charging fees for terminalling services at our facilities. Revenues are also generated by acquiring and marketing crude oil. Generally, crude oil purchases are entered into in contemplation of or simultaneously with corresponding sale transactions involving physical deliveries, which enables us to secure a profit on the transaction at the time of purchase.
|
•
|
Investment in Sunoco LP – Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent operators of commission agent locations, other commercial consumers of motor fuel and to its retail locations. Also included in the segment are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.
|
•
|
Investment in USAC –
USAC provides compression services throughout the United States, including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
927
|
|
|
$
|
626
|
|
|
$
|
301
|
|
Interstate transportation and storage
|
1,680
|
|
|
1,274
|
|
|
406
|
|
|||
Midstream
|
1,627
|
|
|
1,481
|
|
|
146
|
|
|||
NGL and refined products transportation and services
|
1,979
|
|
|
1,641
|
|
|
338
|
|
|||
Crude oil transportation and services
|
2,330
|
|
|
1,379
|
|
|
951
|
|
|||
Investment in Sunoco LP
|
638
|
|
|
732
|
|
|
(94
|
)
|
|||
Investment in USAC
|
289
|
|
|
—
|
|
|
289
|
|
|||
All other
|
76
|
|
|
219
|
|
|
(143
|
)
|
|||
Total Segment Adjusted EBITDA
|
9,546
|
|
|
7,352
|
|
|
2,194
|
|
|||
Depreciation, depletion and amortization
|
(2,843
|
)
|
|
(2,541
|
)
|
|
(302
|
)
|
|||
Interest expense, net
|
(1,709
|
)
|
|
(1,575
|
)
|
|
(134
|
)
|
|||
Impairment losses
|
(431
|
)
|
|
(1,039
|
)
|
|
608
|
|
|||
Gains (losses) on interest rate derivatives
|
47
|
|
|
(37
|
)
|
|
84
|
|
|||
Non-cash compensation expense
|
(105
|
)
|
|
(99
|
)
|
|
(6
|
)
|
|||
Unrealized gains (losses) on commodity risk management activities
|
(11
|
)
|
|
59
|
|
|
(70
|
)
|
|||
Inventory valuation adjustments
|
(85
|
)
|
|
24
|
|
|
(109
|
)
|
|||
Losses on extinguishments of debt
|
(109
|
)
|
|
(42
|
)
|
|
(67
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
(655
|
)
|
|
(716
|
)
|
|
61
|
|
|||
Equity in earnings of unconsolidated affiliates
|
344
|
|
|
144
|
|
|
200
|
|
|||
Impairment of investments in unconsolidated affiliates
|
—
|
|
|
(313
|
)
|
|
313
|
|
|||
Adjusted EBITDA related to discontinued operations
|
25
|
|
|
(223
|
)
|
|
248
|
|
|||
Other, net
|
30
|
|
|
154
|
|
|
(124
|
)
|
|||
Income from continuing operations before income tax (expense) benefit
|
4,044
|
|
|
1,148
|
|
|
2,896
|
|
|||
Income tax (expense) benefit from continuing operations
|
(5
|
)
|
|
1,804
|
|
|
(1,809
|
)
|
|||
Income from continuing operations
|
4,039
|
|
|
2,952
|
|
|
1,087
|
|
|||
Loss from discontinued operations, net of income taxes
|
(265
|
)
|
|
(177
|
)
|
|
(88
|
)
|
|||
Net income
|
$
|
3,774
|
|
|
$
|
2,775
|
|
|
$
|
999
|
|
•
|
an increase of
$121 million
recognized by the Partnership primarily related to an increase in long-term debt, including additional senior note issuances and borrowings under our revolving credit facilities; and
|
•
|
an increase of
$78 million
due to the acquisition of USAC on April 2, 2018; offset by
|
•
|
a decrease of
$65 million
recognized by Sunoco LP primarily due to the repayment in full of its term loan and lower interest rates on its senior notes as a result of Sunoco LP’s January 23, 2018 issuance of senior notes which paid off in full Sunoco LP’s previously outstanding senior notes which had higher interest rates.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Equity in earnings (losses) of unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
141
|
|
|
$
|
144
|
|
|
$
|
(3
|
)
|
FEP
|
55
|
|
|
53
|
|
|
2
|
|
|||
MEP
|
31
|
|
|
38
|
|
|
(7
|
)
|
|||
HPC
(1)(2)
|
3
|
|
|
(168
|
)
|
|
171
|
|
|||
Other
|
114
|
|
|
77
|
|
|
37
|
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
344
|
|
|
$
|
144
|
|
|
$
|
200
|
|
|
|
|
|
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
(3)
:
|
|
|
|
|
|
||||||
Citrus
|
$
|
337
|
|
|
$
|
336
|
|
|
$
|
1
|
|
FEP
|
74
|
|
|
74
|
|
|
—
|
|
|||
MEP
|
81
|
|
|
88
|
|
|
(7
|
)
|
|||
HPC
(2)
|
9
|
|
|
46
|
|
|
(37
|
)
|
|||
Other
|
154
|
|
|
172
|
|
|
(18
|
)
|
|||
Total Adjusted EBITDA related to unconsolidated affiliates
|
$
|
655
|
|
|
$
|
716
|
|
|
$
|
(61
|
)
|
|
|
|
|
|
|
||||||
Distributions received from unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
171
|
|
|
$
|
156
|
|
|
$
|
15
|
|
FEP
|
68
|
|
|
47
|
|
|
21
|
|
|||
MEP
|
48
|
|
|
114
|
|
|
(66
|
)
|
|||
HPC
(2)
|
—
|
|
|
35
|
|
|
(35
|
)
|
|||
Other
|
111
|
|
|
80
|
|
|
31
|
|
|||
Total distributions received from unconsolidated affiliates
|
$
|
398
|
|
|
$
|
432
|
|
|
$
|
(34
|
)
|
(1)
|
For the year ended
December 31, 2017
, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by
$185 million
.
|
(2)
|
The partnership previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, we acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in our financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in our financial statements.
|
(3)
|
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 margin, operating expenses,
and
selling, general and administrative expenses
. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
|
•
|
Unrealized gains or losses on commodity risk management activities
and
inventory valuation adjustments
. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
|
•
|
Non-cash compensation expense
. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
|
•
|
Adjusted EBITDA related to unconsolidated affiliates
. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.
|
|
Years Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Segment Margin:
|
|
|
|
||||
Intrastate transportation and storage
|
$
|
1,072
|
|
|
$
|
756
|
|
Interstate transportation and storage
|
1,682
|
|
|
1,131
|
|
||
Midstream
|
2,377
|
|
|
2,182
|
|
||
NGL and refined products transportation and services
|
2,661
|
|
|
2,140
|
|
||
Crude oil transportation and services
|
2,893
|
|
|
1,877
|
|
||
Investment in Sunoco LP
|
1,122
|
|
|
1,108
|
|
||
Investment in USAC
|
441
|
|
|
—
|
|
||
All other
|
222
|
|
|
392
|
|
||
Intersegment eliminations
|
(41
|
)
|
|
(29
|
)
|
||
Total segment margin
|
12,429
|
|
|
9,557
|
|
||
Less:
|
|
|
|
||||
Operating expenses
|
3,089
|
|
|
2,644
|
|
||
Depreciation, depletion and amortization
|
2,843
|
|
|
2,541
|
|
||
Selling, general and administrative
|
664
|
|
|
568
|
|
||
Impairment losses
|
431
|
|
|
1,039
|
|
||
Operating income
|
$
|
5,402
|
|
|
$
|
2,765
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Natural gas transported (BBtu/d)
|
10,873
|
|
|
8,760
|
|
|
2,113
|
|
|||
Revenues
|
$
|
3,737
|
|
|
$
|
3,083
|
|
|
$
|
654
|
|
Cost of products sold
|
2,665
|
|
|
2,327
|
|
|
338
|
|
|||
Segment margin
|
1,072
|
|
|
756
|
|
|
316
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
38
|
|
|
(5
|
)
|
|
43
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(189
|
)
|
|
(168
|
)
|
|
(21
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(27
|
)
|
|
(22
|
)
|
|
(5
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
32
|
|
|
64
|
|
|
(32
|
)
|
|||
Other
|
1
|
|
|
1
|
|
|
—
|
|
|||
Segment Adjusted EBITDA
|
$
|
927
|
|
|
$
|
626
|
|
|
$
|
301
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Transportation fees
|
$
|
525
|
|
|
$
|
448
|
|
|
$
|
77
|
|
Natural gas sales and other (excluding unrealized gains and losses)
|
510
|
|
|
196
|
|
|
314
|
|
|||
Retained fuel revenues (excluding unrealized gains and losses)
|
59
|
|
|
58
|
|
|
1
|
|
|||
Storage margin, including fees (excluding unrealized gains and losses)
|
16
|
|
|
49
|
|
|
(33
|
)
|
|||
Unrealized gains (losses) on commodity risk management activities
|
(38
|
)
|
|
5
|
|
|
(43
|
)
|
|||
Total segment margin
|
$
|
1,072
|
|
|
$
|
756
|
|
|
$
|
316
|
|
•
|
an increase of
$314 million
in realized natural gas sales and other due to higher realized gains from pipeline optimization activity;
|
•
|
a net increase of
$14 million
due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of
$73 million
,
$16 million
and
$6 million
, respectively, and a decrease of
$37 million
in Adjusted EBITDA related to unconsolidated affiliates; and
|
•
|
an increase of
$4 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; partially offset by
|
•
|
a decrease of
$33 million
in realized storage margin primarily due to an adjustment to the Bammel storage inventory, lower storage fees and lower realized derivative gains.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Natural gas transported (BBtu/d)
|
9,542
|
|
|
6,058
|
|
|
3,484
|
|
|||
Natural gas sold (BBtu/d)
|
17
|
|
|
18
|
|
|
(1
|
)
|
|||
Revenues
|
$
|
1,682
|
|
|
$
|
1,131
|
|
|
$
|
551
|
|
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
|
(431
|
)
|
|
(315
|
)
|
|
(116
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
|
(63
|
)
|
|
(41
|
)
|
|
(22
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
492
|
|
|
498
|
|
|
(6
|
)
|
|||
Other
|
—
|
|
|
1
|
|
|
(1
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
1,680
|
|
|
$
|
1,274
|
|
|
$
|
406
|
|
•
|
an increase of
$359 million
associated with the Rover pipeline with increases of
$485 million
in revenues,
$105 million
in net operating expenses and
$21 million
in selling, general and administrative expenses and other; and
|
•
|
an aggregate increase of
$66 million
in revenues, excluding the incremental revenue related to the Rover pipeline discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines; partially offset by
|
•
|
an increase of
$11 million
in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to increases in maintenance project costs due to scope and level of activity; and
|
•
|
a decrease of
$6 million
in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower margins on MEP due to lower rates on renewals of expiring long term contracts.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Gathered volumes (BBtu/d)
|
12,126
|
|
|
10,956
|
|
|
1,170
|
|
|||
NGLs produced (MBbls/d)
|
540
|
|
|
472
|
|
|
68
|
|
|||
Equity NGLs (MBbls/d)
|
29
|
|
|
27
|
|
|
2
|
|
|||
Revenues
|
$
|
7,522
|
|
|
$
|
6,943
|
|
|
$
|
579
|
|
Cost of products sold
|
5,145
|
|
|
4,761
|
|
|
384
|
|
|||
Segment margin
|
2,377
|
|
|
2,182
|
|
|
195
|
|
|||
Unrealized gains on commodity risk management activities
|
—
|
|
|
(15
|
)
|
|
15
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(705
|
)
|
|
(638
|
)
|
|
(67
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(81
|
)
|
|
(78
|
)
|
|
(3
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
33
|
|
|
28
|
|
|
5
|
|
|||
Other
|
3
|
|
|
2
|
|
|
1
|
|
|||
Segment Adjusted EBITDA
|
$
|
1,627
|
|
|
$
|
1,481
|
|
|
$
|
146
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Gathering and processing fee-based revenues
|
$
|
1,807
|
|
|
$
|
1,690
|
|
|
$
|
117
|
|
Non-fee based contracts and processing (excluding unrealized gains and losses)
|
570
|
|
|
477
|
|
|
93
|
|
|||
Unrealized gains on commodity risk management activities
|
—
|
|
|
15
|
|
|
(15
|
)
|
|||
Total segment margin
|
$
|
2,377
|
|
|
$
|
2,182
|
|
|
$
|
195
|
|
•
|
an increase of
$117 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
$60 million
in non fee-based margin due to increased throughput volume in the North Texas and Permian regions;
|
•
|
an increase of
$33 million
in non fee-based margin due to higher crude oil and NGL prices; and
|
•
|
an increase of
$5 million
in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by
|
•
|
an increase of
$67 million
in operating expenses primarily due to increases of
$20 million
in outside services,
$19 million
in materials,
$8 million
in maintenance project costs,
$7 million
in ad valorem taxes,
$6 million
in employee costs and
$6 million
in office expenses; and
|
•
|
an increase of
$3 million
in selling, general and administrative expenses due to higher professional fees.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
NGL transportation volumes (MBbls/d)
|
1,027
|
|
|
863
|
|
|
164
|
|
|||
Refined products transportation volumes (MBbls/d)
|
621
|
|
|
624
|
|
|
(3
|
)
|
|||
NGL and refined products terminal volumes (MBbls/d)
|
812
|
|
|
783
|
|
|
29
|
|
|||
NGL fractionation volumes (MBbls/d)
|
527
|
|
|
427
|
|
|
100
|
|
|||
Revenues
|
$
|
11,123
|
|
|
$
|
8,648
|
|
|
$
|
2,475
|
|
Cost of products sold
|
8,462
|
|
|
6,508
|
|
|
1,954
|
|
|||
Segment margin
|
2,661
|
|
|
2,140
|
|
|
521
|
|
|||
Unrealized gains on commodity risk management activities
|
(86
|
)
|
|
(26
|
)
|
|
(60
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(604
|
)
|
|
(478
|
)
|
|
(126
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(74
|
)
|
|
(64
|
)
|
|
(10
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
82
|
|
|
68
|
|
|
14
|
|
|||
Other
|
—
|
|
|
1
|
|
|
(1
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
1,979
|
|
|
$
|
1,641
|
|
|
$
|
338
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Fractionators and Refinery services margin
|
$
|
592
|
|
|
$
|
488
|
|
|
$
|
104
|
|
Transportation margin
|
1,233
|
|
|
990
|
|
|
243
|
|
|||
Storage margin
|
211
|
|
|
214
|
|
|
(3
|
)
|
|||
Terminal Services margin
|
413
|
|
|
351
|
|
|
62
|
|
|||
Marketing margin
|
126
|
|
|
71
|
|
|
55
|
|
|||
Unrealized gains on commodity risk management activities
|
86
|
|
|
26
|
|
|
60
|
|
|||
Total segment margin
|
$
|
2,661
|
|
|
$
|
2,140
|
|
|
$
|
521
|
|
•
|
an increase in transportation margin of
$243 million
primarily due to a
$216 million
increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines, a
$31 million
increase due to higher throughput volumes on Mariner West driven by end-user facility constraints in the prior period, a
$15 million
increase resulting from a reclassification between our transportation and fractionation margins, a
$9 million
increase due to higher throughput volumes from the Barnett region, a
$5 million
increase due to higher throughput volumes on Mariner South due to system downtime in the prior period and a
$4 million
increase in prior period customer credits. These increases were partially offset by a
$16 million
decrease resulting from lower throughput volumes on Mariner East 1 due to system downtime in 2018, a
$14 million
decrease due to lower throughput volumes from the Southeast Texas region and a
$7 million
decrease resulting from the timing of deficiency fee revenue recognition;
|
•
|
an increase in fractionation and refinery services margin of
$104 million
primarily due to a
$106 million
increase resulting from the commissioning of our fifth fractionator in July 2018, a
$9 million
increase from throughput revenue at our Mariner South export facility and a
$7 million
increase from blending gains as a result of improved market pricing. These increases were partially offset by a
$16 million
decrease resulting from a reclassification between our transportation and fractionation margins and a
$2 million
decrease from higher affiliate storage fees paid;
|
•
|
an increase in terminal services margin of
$62 million
due to a
$36 million
increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses, a
$14 million
increase at our Nederland terminal due to increased export demand and a
$12 million
increase due to higher throughput at our Marcus Hook Industrial Complex. These increases were partially offset by lower terminal throughput fees in part due to the sale of one of our terminals in April 2017;
|
•
|
an increase in marketing margin of
$55 million
due to a
$48 million
increase from our butane blending operations and a
$22 million
increase in sales of NGLs and other products at our Marcus Hook Industrial Complex due to more favorable market prices. These increases were partially offset by a
$15 million
decrease from the timing of optimization gains from our Mont Belvieu fractionators; and
|
•
|
an increase of
$14 million
to adjusted EBITDA related to unconsolidated affiliates due to improved contributions from our unconsolidated refined products joint venture interests; partially offset by
|
•
|
an increase of
$126 million
in operating expenses primarily due to a
$30 million
increase in costs to operate our fractionators and a
$20 million
increase in operating costs on our NGL pipelines as a result of higher throughput and the commissioning of our fifth fractionator in July 2018, a
$36 million
increase 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
|
•
|
an increase of
$10 million
in selling, general and administrative expenses primarily due to a
$6 million
increase in overhead costs allocated to the segment, a
$2 million
increase in legal fees, a
$1 million
increase in management fees previously recorded in operating expenses and a
$1 million
increase in employee costs.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Crude Transportation Volumes (MBbls/d)
|
4,172
|
|
|
3,538
|
|
|
634
|
|
|||
Crude Terminals Volumes (MBbls/d)
|
2,096
|
|
|
1,928
|
|
|
168
|
|
|||
Revenue
|
$
|
17,332
|
|
|
$
|
11,703
|
|
|
$
|
5,629
|
|
Cost of products sold
|
14,439
|
|
|
9,826
|
|
|
4,613
|
|
|||
Segment margin
|
2,893
|
|
|
1,877
|
|
|
1,016
|
|
|||
Unrealized losses on commodity risk management activities
|
55
|
|
|
1
|
|
|
54
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(547
|
)
|
|
(430
|
)
|
|
(117
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(86
|
)
|
|
(82
|
)
|
|
(4
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
15
|
|
|
13
|
|
|
2
|
|
|||
Segment Adjusted EBITDA
|
$
|
2,330
|
|
|
$
|
1,379
|
|
|
$
|
951
|
|
•
|
an increase of
$1.07 billion
in segment margin (excluding unrealized losses on commodity risk management activities) primarily due to the following: a
$586 million
increase resulting from placing the Bakken pipeline in service in the second quarter of 2017; a
$266 million
increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers; and a
$189 million
increase (excluding a net change of
$54 million
in unrealized losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from improved basis differentials between the Permian and Bakken producing regions to our Nederland terminal on the Texas gulf coast; and a
$28 million
increase primarily from higher throughput and ship loading fees at our Nederland terminal; and
|
•
|
an increase of
$2 million
in Adjusted EBITDA related to unconsolidated affiliates due to increased jet fuel sales from our joint ventures; partially offset by
|
•
|
an increase of
$117 million
in operating expenses primarily due to a
$67 million
increase to throughput related costs on existing assets; a
$36 million
increase resulting from placing the Bakken pipeline in service in the second quarter of 2017; a
$26 million
increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a
$5 million
increase from ad valorem taxes; partially offset by an
$17 million
decrease in insurance and environmental related expenses; and
|
•
|
an increase of
$4 million
in selling, general and administrative expenses primarily due to increases associated with placing our Bakken Pipeline in service in the second quarter of 2017.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Revenues
|
$
|
16,994
|
|
|
$
|
11,723
|
|
|
$
|
5,271
|
|
Cost of products sold
|
15,872
|
|
|
10,615
|
|
|
5,257
|
|
|||
Segment margin
|
1,122
|
|
|
1,108
|
|
|
14
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
6
|
|
|
(3
|
)
|
|
9
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(435
|
)
|
|
(456
|
)
|
|
21
|
|
|||
Selling, general and administrative, excluding non-cash compensation expense
|
(129
|
)
|
|
(116
|
)
|
|
(13
|
)
|
|||
Inventory fair value adjustments
|
85
|
|
|
(24
|
)
|
|
109
|
|
|||
Adjusted EBITDA from discontinued operations
|
(25
|
)
|
|
223
|
|
|
(248
|
)
|
|||
Other, net
|
14
|
|
|
—
|
|
|
14
|
|
|||
Segment Adjusted EBITDA
|
$
|
638
|
|
|
$
|
732
|
|
|
$
|
(94
|
)
|
•
|
a decrease of
$248 million
in Adjusted EBITDA from discontinued operations primarily due to Sunoco LP’s retail divestment in January 2018; partially offset by
|
•
|
an increase of
$109 million
in inventory fair value adjustments due to changes in fuel prices between periods;
|
•
|
an increase of
$14 million
in margin primarily due to an increase in rental income as a result of the increase in commission agent sites in the current year, offset by decreases in the gross profit on motor fuel sales; and
|
•
|
a net decrease of
$8 million
in operating and selling, general and administrative expenses primarily due to decreased rent expense.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Revenues
|
$
|
508
|
|
|
$
|
—
|
|
|
$
|
508
|
|
Cost of products sold
|
67
|
|
|
—
|
|
|
67
|
|
|||
Segment margin
|
441
|
|
|
—
|
|
|
441
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(110
|
)
|
|
—
|
|
|
(110
|
)
|
|||
Selling, general and administrative, excluding non-cash compensation expense
|
(50
|
)
|
|
—
|
|
|
(50
|
)
|
|||
Other, net
|
8
|
|
|
—
|
|
|
8
|
|
|||
Segment Adjusted EBITDA
|
$
|
289
|
|
|
$
|
—
|
|
|
$
|
289
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Revenue
|
$
|
2,228
|
|
|
$
|
2,901
|
|
|
$
|
(673
|
)
|
Cost of products sold
|
2,006
|
|
|
2,509
|
|
|
(503
|
)
|
|||
Segment margin
|
222
|
|
|
392
|
|
|
(170
|
)
|
|||
Unrealized gains on commodity risk management activities
|
(2
|
)
|
|
(11
|
)
|
|
9
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(56
|
)
|
|
(117
|
)
|
|
61
|
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(87
|
)
|
|
(103
|
)
|
|
16
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
1
|
|
|
45
|
|
|
(44
|
)
|
|||
Other and eliminations
|
(2
|
)
|
|
13
|
|
|
(15
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
76
|
|
|
$
|
219
|
|
|
$
|
(143
|
)
|
•
|
our natural gas marketing operations;
|
•
|
our wholly-owned natural gas compression operations;
|
•
|
a non-controlling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s
33%
interest in PES was reflected as an unconsolidated affiliate; subsequent the August 2018 reorganization, ETO holds an approximately
8%
interest in PES and no longer reflects PES as an affiliate; and
|
•
|
our investment in coal handling facilities.
|
•
|
a decrease of
$98 million
due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;
|
•
|
a decrease of
$38 million
in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES primarily due to our 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;
|
•
|
a decrease of
$4 million
due to merger and acquisition expenses related to the Energy Transfer Merger in 2018; and
|
•
|
a decrease of
$15 million
due to a one-time fee received from a joint venture affiliate in 2017; partially offset by
|
•
|
an increase of
$7 million
due to lower transport fees resulting from the expiration of a capacity commitment on Trunkline pipeline;
|
•
|
an increase of
$6 million
due to a decrease in losses from mark-to-market of physical system gas; and
|
•
|
an increase of
$7 million
due to increased margin from ETO’s compression equipment business.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
626
|
|
|
$
|
613
|
|
|
$
|
13
|
|
Interstate transportation and storage
|
1,274
|
|
|
1,297
|
|
|
(23
|
)
|
|||
Midstream
|
1,481
|
|
|
1,133
|
|
|
348
|
|
|||
NGL and refined products transportation and services
|
1,641
|
|
|
1,496
|
|
|
145
|
|
|||
Crude oil transportation and services
|
1,379
|
|
|
834
|
|
|
545
|
|
|||
Investment in Sunoco LP
|
732
|
|
|
665
|
|
|
67
|
|
|||
All other
|
219
|
|
|
193
|
|
|
26
|
|
|||
Total
|
7,352
|
|
|
6,231
|
|
|
1,121
|
|
|||
Depreciation, depletion and amortization
|
(2,541
|
)
|
|
(2,201
|
)
|
|
(340
|
)
|
|||
Interest expense, net
|
(1,575
|
)
|
|
(1,478
|
)
|
|
(97
|
)
|
|||
Gains on acquisitions
|
—
|
|
|
83
|
|
|
(83
|
)
|
|||
Impairment losses
|
(1,039
|
)
|
|
(1,040
|
)
|
|
1
|
|
|||
Losses on interest rate derivatives
|
(37
|
)
|
|
(12
|
)
|
|
(25
|
)
|
|||
Non-cash compensation expense
|
(99
|
)
|
|
(93
|
)
|
|
(6
|
)
|
|||
Unrealized (gains) losses on commodity risk management activities
|
59
|
|
|
(136
|
)
|
|
195
|
|
|||
Inventory valuation adjustments
|
24
|
|
|
97
|
|
|
(73
|
)
|
|||
Losses on extinguishments of debt
|
(42
|
)
|
|
—
|
|
|
(42
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
(716
|
)
|
|
(675
|
)
|
|
(41
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
144
|
|
|
270
|
|
|
(126
|
)
|
|||
Impairment of investment in an unconsolidated affiliate
|
(313
|
)
|
|
(308
|
)
|
|
(5
|
)
|
|||
Adjusted EBITDA related to discontinued operations
|
(223
|
)
|
|
(199
|
)
|
|
(24
|
)
|
|||
Other, net
|
154
|
|
|
117
|
|
|
37
|
|
|||
Income before income tax benefit
|
1,148
|
|
|
656
|
|
|
492
|
|
|||
Income tax benefit from continuing operations
|
1,804
|
|
|
255
|
|
|
1,549
|
|
|||
Income from continuing operations
|
2,952
|
|
|
911
|
|
|
2,041
|
|
|||
Loss from discontinued operations, net of income taxes
|
(177
|
)
|
|
(462
|
)
|
|
285
|
|
|||
Net income
|
$
|
2,775
|
|
|
$
|
449
|
|
|
$
|
2,326
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Equity in earnings (losses) of unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
144
|
|
|
$
|
102
|
|
|
$
|
42
|
|
FEP
|
53
|
|
|
51
|
|
|
2
|
|
|||
MEP
|
38
|
|
|
40
|
|
|
(2
|
)
|
|||
HPC
(1)
|
(168
|
)
|
|
31
|
|
|
(199
|
)
|
|||
Other
|
77
|
|
|
46
|
|
|
31
|
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
144
|
|
|
$
|
270
|
|
|
$
|
(126
|
)
|
|
|
|
|
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
(2)
:
|
|
|
|
|
|
||||||
Citrus
|
$
|
336
|
|
|
$
|
329
|
|
|
$
|
7
|
|
FEP
|
74
|
|
|
75
|
|
|
(1
|
)
|
|||
MEP
|
88
|
|
|
90
|
|
|
(2
|
)
|
|||
HPC
|
46
|
|
|
61
|
|
|
(15
|
)
|
|||
Other
|
172
|
|
|
120
|
|
|
52
|
|
|||
Total Adjusted EBITDA related to unconsolidated affiliates
|
$
|
716
|
|
|
$
|
675
|
|
|
$
|
41
|
|
|
|
|
|
|
|
||||||
Distributions received from unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
156
|
|
|
$
|
144
|
|
|
$
|
12
|
|
FEP
|
47
|
|
|
65
|
|
|
(18
|
)
|
|||
MEP
|
114
|
|
|
74
|
|
|
40
|
|
|||
HPC
|
35
|
|
|
51
|
|
|
(16
|
)
|
|||
Other
|
80
|
|
|
69
|
|
|
11
|
|
|||
Total distributions received from unconsolidated affiliates
|
$
|
432
|
|
|
$
|
403
|
|
|
$
|
29
|
|
(1)
|
For the year ended
December 31, 2017
, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by
$185 million
.
|
(2)
|
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.
|
|
Years Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
Segment Margin:
|
|
|
|
||||
Intrastate transportation and storage
|
$
|
756
|
|
|
$
|
716
|
|
Interstate transportation and storage
|
1,131
|
|
|
1,166
|
|
||
Midstream
|
2,182
|
|
|
1,798
|
|
||
NGL and refined products transportation and services
|
2,140
|
|
|
1,856
|
|
||
Crude oil transportation and services
|
1,877
|
|
|
1,123
|
|
||
Investment in Sunoco LP
|
1,108
|
|
|
1,156
|
|
||
All other
|
392
|
|
|
330
|
|
||
Intersegment eliminations
|
(29
|
)
|
|
(46
|
)
|
||
Total segment margin
|
9,557
|
|
|
8,099
|
|
||
Less:
|
|
|
|
||||
Operating expenses
|
2,644
|
|
|
2,336
|
|
||
Depreciation, depletion and amortization
|
2,541
|
|
|
2,201
|
|
||
Selling, general and administrative
|
568
|
|
|
547
|
|
||
Impairment losses
|
1,039
|
|
|
1,040
|
|
||
Operating income
|
$
|
2,765
|
|
|
$
|
1,975
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Natural gas transported (BBtu/d)
|
8,760
|
|
|
8,328
|
|
|
432
|
|
|||
Revenues
|
$
|
3,083
|
|
|
$
|
2,613
|
|
|
$
|
470
|
|
Cost of products sold
|
2,327
|
|
|
1,897
|
|
|
430
|
|
|||
Segment margin
|
756
|
|
|
716
|
|
|
40
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
(5
|
)
|
|
19
|
|
|
(24
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(168
|
)
|
|
(162
|
)
|
|
(6
|
)
|
|||
Selling, general and administrative, excluding non-cash compensation expense
|
(22
|
)
|
|
(22
|
)
|
|
—
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
64
|
|
|
61
|
|
|
3
|
|
|||
Other
|
1
|
|
|
1
|
|
|
—
|
|
|||
Segment Adjusted EBITDA
|
$
|
626
|
|
|
$
|
613
|
|
|
$
|
13
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Transportation fees
|
$
|
448
|
|
|
$
|
505
|
|
|
$
|
(57
|
)
|
Natural gas sales and other (excluding unrealized gains and losses)
|
196
|
|
|
118
|
|
|
78
|
|
|||
Retained fuel revenues (excluding unrealized gains and losses)
|
58
|
|
|
51
|
|
|
7
|
|
|||
Storage margin, including fees (excluding unrealized gains and losses)
|
49
|
|
|
61
|
|
|
(12
|
)
|
|||
Unrealized gains (losses) on commodity risk management activities
|
5
|
|
|
(19
|
)
|
|
24
|
|
|||
Total segment margin
|
$
|
756
|
|
|
$
|
716
|
|
|
$
|
40
|
|
•
|
an increase of
$78 million
in natural gas sales and other primarily due to higher realized gains from pipeline optimization activity;
|
•
|
an increase of
$7 million
in retained fuel sales primarily due to higher market prices. The average spot price at the Houston Ship Channel location increased 22% for the year ended December 31, 2017 compared to the prior year; and
|
•
|
an increase of
$3 million
in adjusted EBITDA related to unconsolidated affiliates primarily due to an increase of
$16 million
related to two new joint venture pipelines placed in service in 2017, offset by a decrease of
$6 million
due to lower demand volumes related to renegotiation of a contract on our Louisiana intrastate pipeline system in 2017 and a decrease of
$7 million
due to a reserve recorded in 2017 pursuant to the bankruptcy filing of a transport customer on our Louisiana intrastate system; partially offset by
|
•
|
a decrease of
$57 million
in transportation fees due to renegotiated contracts resulting in lower billed volumes. This decrease was offset by increased margin from optimization activity recorded in natural gas sales and other;
|
•
|
a decrease of
$12 million
in storage margin due to the timing of withdrawals and sales of natural gas from our Bammel storage cavern; and
|
•
|
an increase of
$6 million
in operating expenses primarily due to higher compression fuel expense relating to increased market price and run times at various compressor stations.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Natural gas transported (BBtu/d)
|
6,058
|
|
|
5,476
|
|
|
582
|
|
|||
Natural gas sold (BBtu/d)
|
18
|
|
|
19
|
|
|
(1
|
)
|
|||
Revenues
|
$
|
1,131
|
|
|
$
|
1,166
|
|
|
$
|
(35
|
)
|
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
|
(315
|
)
|
|
(318
|
)
|
|
3
|
|
|||
Selling, general and administrative, excluding non-cash compensation, amortization and accretion expenses
|
(41
|
)
|
|
(40
|
)
|
|
(1
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
498
|
|
|
494
|
|
|
4
|
|
|||
Other
|
1
|
|
|
(5
|
)
|
|
6
|
|
|||
Segment Adjusted EBITDA
|
$
|
1,274
|
|
|
$
|
1,297
|
|
|
$
|
(23
|
)
|
•
|
a net decrease of
$35 million
in revenues primarily due to a decrease in reservation revenues of
$45 million
on the Panhandle, Trunkline and Transwestern pipelines, a decrease of
$17 million
in gas parking service related revenues on the Panhandle and Trunkline pipelines primarily due to lack of customer demand resulting from weak spreads, a decrease of
$19 million
in revenues on the Tiger pipeline due to contract restructuring, and a decrease of
$5 million
on the Sea Robin pipeline due to producer maintenance and production declines. These decreases were partially offset by
$55 million
of incremental revenues from the placement in partial service of the Rover pipeline effective August 31, 2017; partially offset by
|
•
|
a decrease of
$3 million
in operating expenses primarily due to lower allocated costs of
$8 million
and lower lease storage expense of
$4 million
due to expiration of a lease. These decreases were partially offset by higher ad valorem taxes resulting from higher valuations;
|
•
|
an increase of
$4 million
in adjusted EBITDA related to unconsolidated affiliates due to an increase of
$6 million
related to a legal settlement, an increase of
$3 million
resulting from higher sales of short-term firm capacity on Citrus and
$2 million
related to higher tax gross up income from reimbursable projects on Citrus. These increases were partially offset by lower reservation revenues on MEP primarily due to a contract modification and expiring contracts; and
|
•
|
an increase of
$6 million
in other primarily due to higher tax gross up income from reimbursable projects.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Gathered volumes (BBtu/d):
|
10,956
|
|
|
9,814
|
|
|
1,142
|
|
|||
NGLs produced (MBbls/d):
|
472
|
|
|
438
|
|
|
34
|
|
|||
Equity NGLs (MBbls/d):
|
27
|
|
|
31
|
|
|
(4
|
)
|
|||
Revenues
|
$
|
6,943
|
|
|
$
|
5,179
|
|
|
$
|
1,764
|
|
Cost of products sold
|
4,761
|
|
|
3,381
|
|
|
1,380
|
|
|||
Segment margin
|
2,182
|
|
|
1,798
|
|
|
384
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
(15
|
)
|
|
15
|
|
|
(30
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(638
|
)
|
|
(621
|
)
|
|
(17
|
)
|
|||
Selling, general and administrative, excluding non-cash compensation expense
|
(78
|
)
|
|
(84
|
)
|
|
6
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
28
|
|
|
24
|
|
|
4
|
|
|||
Other
|
2
|
|
|
1
|
|
|
1
|
|
|||
Segment Adjusted EBITDA
|
$
|
1,481
|
|
|
$
|
1,133
|
|
|
$
|
348
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Gathering and processing fee-based revenues
|
$
|
1,690
|
|
|
$
|
1,551
|
|
|
$
|
139
|
|
Non-fee based contracts and processing (excluding unrealized gains and losses)
|
477
|
|
|
262
|
|
|
215
|
|
|||
Unrealized gains (losses) on commodity risk management activities
|
15
|
|
|
(15
|
)
|
|
30
|
|
|||
Total segment margin
|
$
|
2,182
|
|
|
$
|
1,798
|
|
|
$
|
384
|
|
•
|
an increase of
$150 million
in non-fee based margins due to higher crude oil and NGL prices;
|
•
|
an increase of
$65 million
in non-fee based margin due to volume increases in the Permian, Northeast and South Texas regions, partially offset by volume declines in the North Texas and the Midcontinent/Panhandle regions;
|
•
|
an increase of
$75 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 the North Texas and the Midcontinent/Panhandle regions;
|
•
|
an increase of
$64 million
in fee-based revenue due to recent acquisitions, including PennTex; and
|
•
|
a decrease of
$6 million
in selling, general and administrative expenses primarily due to a favorable impact from the adjustment of certain reserves that had previously been recorded in connection with contingent matters. This decrease was partially offset by a decrease in capitalized overhead of
$11 million
and an increase in shared services allocation of
$14 million
; partially offset by
|
•
|
an increase of
$17 million
in operating expenses primarily due to recent acquisitions, including PennTex.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
NGL transportation volumes (MBbls/d)
|
863
|
|
|
754
|
|
|
109
|
|
|||
Refined products transportation volumes (MBbls/d)
|
624
|
|
|
599
|
|
|
25
|
|
|||
NGL and refined products terminal volumes (MBbls/d)
|
783
|
|
|
791
|
|
|
(8
|
)
|
|||
NGL fractionation volumes (MBbls/d)
|
427
|
|
|
361
|
|
|
66
|
|
|||
Revenues
|
$
|
8,648
|
|
|
$
|
6,409
|
|
|
$
|
2,239
|
|
Cost of products sold
|
6,508
|
|
|
4,553
|
|
|
1,955
|
|
|||
Segment margin
|
2,140
|
|
|
1,856
|
|
|
284
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
(26
|
)
|
|
69
|
|
|
(95
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(478
|
)
|
|
(441
|
)
|
|
(37
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(64
|
)
|
|
(56
|
)
|
|
(8
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
68
|
|
|
67
|
|
|
1
|
|
|||
Other
|
1
|
|
|
1
|
|
|
—
|
|
|||
Segment Adjusted EBITDA
|
$
|
1,641
|
|
|
$
|
1,496
|
|
|
$
|
145
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Fractionators and Refinery services margin
|
$
|
488
|
|
|
$
|
407
|
|
|
$
|
81
|
|
Transportation margin
|
990
|
|
|
866
|
|
|
124
|
|
|||
Storage margin
|
214
|
|
|
208
|
|
|
6
|
|
|||
Terminal Services margin
|
351
|
|
|
322
|
|
|
29
|
|
|||
Marketing margin
|
71
|
|
|
122
|
|
|
(51
|
)
|
|||
Unrealized gains (losses) on commodity risk management activities
|
26
|
|
|
(69
|
)
|
|
95
|
|
|||
Total segment margin
|
$
|
2,140
|
|
|
$
|
1,856
|
|
|
$
|
284
|
|
•
|
an increase of
$124 million
in transportation margin primarily due to increased throughput on our Texas NGL pipelines resulting from increased producer services as noted above and the ramp up of volumes on our Mariner East system;
|
•
|
an increase of
$81 million
in fractionation and refinery services margin primarily due to higher NGL volumes from most major producing regions feeding our Mont Belvieu fractionation facility, the first full year of service for our fourth fractionator at Mont Belvieu, Texas and a
$17 million
increase from blending gains as a result of improved market pricing, as noted above;
|
•
|
an increase of
$29 million
in terminal services margin due to a
$43 million
increase resulting from higher throughput volumes at our Marcus Hook and Nederland NGL terminals. This increase was partially offset by a
$14 million
decrease resulting from lower refined products terminal throughput and the sale of one of our refined product terminals in April 2017; and
|
•
|
an increase of
$6 million
in storage margin primarily due to a
$4 million
increase from Hattiesburg storage caverns as a result of a new storage contract effective in April 2017 as well as a
$2 million
increase from propane and butane blending gains as a result of improved market pricing; offset by
|
•
|
a decrease of
$51 million
in marketing margin primarily due to the timing of the recognition of margin from optimization activities;
|
•
|
an increase of
$37 million
in operating expenses due to a
$16 million
increase related to the fourth fractionator being placed into service in October 2016, an
$11 million
increase related to higher utility expenses on our Texas NGL pipelines, a
$5 million
increase due to higher right-of-way expenses primarily on our legacy Sunoco Logistics assets and a
$4 million
increase from our Mont Belvieu storage assets primarily due to higher employee costs; and
|
•
|
an increase of
$8 million
in selling, general and administrative expenses due to higher allocations.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Crude Transportation Volumes (MBbls/d)
|
3,538
|
|
|
2,652
|
|
|
886
|
|
|||
Crude Terminals Volumes (MBbls/d)
|
1,928
|
|
|
1,537
|
|
|
391
|
|
|||
Revenue
|
$
|
11,703
|
|
|
$
|
7,539
|
|
|
$
|
4,164
|
|
Cost of products sold
|
9,826
|
|
|
6,416
|
|
|
3,410
|
|
|||
Segment margin
|
1,877
|
|
|
1,123
|
|
|
754
|
|
|||
Unrealized losses on commodity risk management activities
|
1
|
|
|
2
|
|
|
(1
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(430
|
)
|
|
(247
|
)
|
|
(183
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(82
|
)
|
|
(58
|
)
|
|
(24
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
13
|
|
|
14
|
|
|
(1
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
1,379
|
|
|
$
|
834
|
|
|
$
|
545
|
|
•
|
an increase of
$724 million
resulting primarily from placing our Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas and the addition of joint venture crude transportation assets;
|
•
|
an increase of
$90 million
from existing transportation assets due to increased volumes throughout the system; and
|
•
|
an increase of
$16 million
from increased throughput fees and tank rentals, primarily from increased activity at our Nederland, Texas crude terminal; partially offset by
|
•
|
a decrease of
$78 million
in margin from our crude oil acquisition and marketing business resulting from less favorable market price spreads particularly in the first three quarters of 2017;
|
•
|
an increase of
$183 million
in operating expenses primarily due to an increase of
$130 million
resulting primarily from placing the Bakken Pipeline as well as certain joint venture crude transportation assets in service in the first and second quarters of 2017, respectively, an increase of
$46 million
due to higher utilities, line testing, and environmental costs from existing transport assets and an increase of
$6 million
for losses related to Hurricane Harvey; and
|
•
|
an increase of
$24 million
in selling, general and administrative expenses primarily due to merger fees and legal and environmental reserves.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Revenues
|
$
|
11,723
|
|
|
$
|
9,986
|
|
|
$
|
1,737
|
|
Cost of products sold
|
10,615
|
|
|
8,830
|
|
|
1,785
|
|
|||
Segment margin
|
1,108
|
|
|
1,156
|
|
|
(48
|
)
|
|||
Unrealized (gains) losses on commodity risk management activities
|
(3
|
)
|
|
5
|
|
|
(8
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(456
|
)
|
|
(455
|
)
|
|
(1
|
)
|
|||
Selling, general and administrative, excluding non-cash compensation expense
|
(116
|
)
|
|
(143
|
)
|
|
27
|
|
|||
Inventory valuation adjustments
|
(24
|
)
|
|
(97
|
)
|
|
73
|
|
|||
Adjusted EBITDA from discontinued operations
|
223
|
|
|
199
|
|
|
24
|
|
|||
Segment Adjusted EBITDA
|
$
|
732
|
|
|
$
|
665
|
|
|
$
|
67
|
|
•
|
an increase of
$18 million
in gross margin (excluding a
$65 million
change in fair value adjustments related to inventory and unrealized gains and losses on commodity risk management activities) primarily caused by an increase in wholesale motor fuel gross profit per gallon, partially offset by a net increase in other gross profit consisting of merchandise, rental & other and retail motor fuel of
$13 million
;
|
•
|
a decrease of
$27 million
in general and administrative expenses primarily due to higher costs in 2016 related to relocation, employee termination, and higher contract labor and professional fees as the Partnership transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas to Dallas during 2016; and
|
•
|
an increase of
$24 million
related to discontinued operations; partially offset by
|
•
|
an increase of
$1 million
in other operating expenses primarily attributable to Sunoco LP’s retail business which has expanded through third-party acquisitions as well as through the construction of new-to-industry sites.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Revenue
|
$
|
2,901
|
|
|
$
|
3,272
|
|
|
$
|
(371
|
)
|
Cost of products sold
|
2,509
|
|
|
2,942
|
|
|
(433
|
)
|
|||
Segment margin
|
392
|
|
|
330
|
|
|
62
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
(11
|
)
|
|
26
|
|
|
(37
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(117
|
)
|
|
(79
|
)
|
|
(38
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(103
|
)
|
|
(86
|
)
|
|
(17
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
45
|
|
|
15
|
|
|
30
|
|
|||
Other and eliminations
|
13
|
|
|
(13
|
)
|
|
26
|
|
|||
Segment Adjusted EBITDA
|
$
|
219
|
|
|
$
|
193
|
|
|
$
|
26
|
|
•
|
our natural gas marketing operations;
|
•
|
our wholly-owned natural gas compression operations;
|
•
|
a non-controlling interest in PES, representing approximately 33% of PES’ outstanding common units for the periods presented above; and
|
•
|
our investment in coal handling facilities.
|
•
|
an increase of
$33 million
in Adjusted EBITDA related to our investment in PES;
|
•
|
an increase of
$20 million
in crude and power trading activates, primarily from the liquidation of crude inventories;
|
•
|
a one-time fee of
$15 million
received from a joint venture affiliate; and
|
•
|
a decrease of
$11 million
in expenses related to our compression business; partially offset by
|
•
|
a decrease of
$31 million
from the mark-to-market of physical system gas and settled derivatives;
|
•
|
an increase of
$17 million
in selling, general and administrative expenses primarily from higher transaction-related expenses; and
|
•
|
a decrease of
$15 million
in income related to the termination of management fees paid by ET that ended in the first quarter of 2017.
|
|
Growth
|
|
Maintenance
|
||||||||||||
|
Low
|
|
High
|
|
Low
|
|
High
|
||||||||
Intrastate transportation and storage
|
$
|
125
|
|
|
$
|
175
|
|
|
$
|
35
|
|
|
$
|
40
|
|
Interstate transportation and storage
(1)
|
175
|
|
|
200
|
|
|
140
|
|
|
145
|
|
||||
Midstream
|
750
|
|
|
850
|
|
|
115
|
|
|
120
|
|
||||
NGL and refined products transportation and services
|
3,100
|
|
|
3,200
|
|
|
90
|
|
|
100
|
|
||||
Crude oil transportation and services
(1)
|
575
|
|
|
650
|
|
|
90
|
|
|
100
|
|
||||
All other (including eliminations)
|
125
|
|
|
150
|
|
|
50
|
|
|
55
|
|
||||
Total capital expenditures
|
$
|
4,850
|
|
|
$
|
5,225
|
|
|
$
|
520
|
|
|
$
|
560
|
|
(1)
|
Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.
|
•
|
maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of its assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining its existing business and related operating income; and
|
•
|
expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that were not currently generating operating income.
|
|
Capital Expenditures Recorded During Period
|
||||||||||
Growth
|
|
Maintenance
|
|
Total
|
|||||||
Year Ended December 31, 2018:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
311
|
|
|
$
|
33
|
|
|
$
|
344
|
|
Interstate transportation and storage
|
695
|
|
|
117
|
|
|
812
|
|
|||
Midstream
|
1,026
|
|
|
135
|
|
|
1,161
|
|
|||
NGL and refined products transportation and services
|
2,303
|
|
|
78
|
|
|
2,381
|
|
|||
Crude oil transportation and services
|
414
|
|
|
60
|
|
|
474
|
|
|||
Investment in Sunoco LP
|
72
|
|
|
31
|
|
|
103
|
|
|||
Investment in USAC
(1)
|
182
|
|
|
23
|
|
|
205
|
|
|||
All other (including eliminations)
|
117
|
|
|
33
|
|
|
150
|
|
|||
Total capital expenditures
|
$
|
5,120
|
|
|
$
|
510
|
|
|
$
|
5,630
|
|
|
|
|
|
|
|
||||||
Year Ended December 31, 2017:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
155
|
|
|
$
|
20
|
|
|
$
|
175
|
|
Interstate transportation and storage
|
645
|
|
|
83
|
|
|
728
|
|
|||
Midstream
|
1,185
|
|
|
123
|
|
|
1,308
|
|
|||
NGL and refined products transportation and services
|
2,899
|
|
|
72
|
|
|
2,971
|
|
|||
Crude oil transportation and services
|
392
|
|
|
61
|
|
|
453
|
|
|||
Investment in Sunoco LP
(2)
|
129
|
|
|
48
|
|
|
177
|
|
|||
All other (including eliminations)
|
196
|
|
|
72
|
|
|
268
|
|
|||
Total capital expenditures
|
$
|
5,601
|
|
|
$
|
479
|
|
|
$
|
6,080
|
|
|
|
|
|
|
|
||||||
Year Ended December 31, 2016:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
53
|
|
|
$
|
23
|
|
|
$
|
76
|
|
Interstate transportation and storage
|
191
|
|
|
89
|
|
|
280
|
|
|||
Midstream
|
1,133
|
|
|
122
|
|
|
1,255
|
|
|||
NGL and refined products transportation and services
|
2,150
|
|
|
48
|
|
|
2,198
|
|
|||
Crude oil transportation and services
|
1,806
|
|
|
35
|
|
|
1,841
|
|
|||
Investment in Sunoco LP
(2)
|
333
|
|
|
106
|
|
|
439
|
|
|||
All other (including eliminations)
|
109
|
|
|
51
|
|
|
160
|
|
|||
Total capital expenditures
|
$
|
5,775
|
|
|
$
|
474
|
|
|
$
|
6,249
|
|
(1)
|
Amounts related to USAC capital expenditures (net of contributions in aid of construction costs) for 2018 are subsequent to the close of the CDM Contribution on April 2, 2018 as discussed in “Recent Developments.”
|
(2)
|
Amounts related to Sunoco LP’s capital expenditures include capital expenditures related to discontinued operations.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
ETO Senior Notes
|
$
|
28,755
|
|
|
$
|
27,005
|
|
Transwestern Senior Notes
|
575
|
|
|
575
|
|
||
Panhandle Senior Notes
|
385
|
|
|
785
|
|
||
Sunoco LP Senior Notes, Term Loan and lease-related obligations
|
2,307
|
|
|
3,556
|
|
||
USAC Senior Notes due April 1, 2026
|
725
|
|
|
—
|
|
||
Revolving credit facilities:
|
|
|
|
||||
ETO $5.00 billion Revolving Credit Facility due December 2023
|
3,694
|
|
|
2,292
|
|
||
ETO $1.00 billion 364-Day Credit Facility due November 2019
|
—
|
|
|
50
|
|
||
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023
|
700
|
|
|
—
|
|
||
Sunoco LP $1.50 billion Revolving Credit Facility due September 2019
|
—
|
|
|
765
|
|
||
USAC $1.60 billion Revolving Credit Facility due April 2023
|
1,050
|
|
|
—
|
|
||
Bakken $2.50 billion Credit Facility due August 2019
|
2,500
|
|
|
2,500
|
|
||
Other long-term debt
|
7
|
|
|
8
|
|
||
Unamortized premiums, net of discounts and fair value adjustments
|
31
|
|
|
61
|
|
||
Deferred debt issuance costs
|
(221
|
)
|
|
(213
|
)
|
||
Total debt
|
40,508
|
|
|
37,384
|
|
||
Less: current maturities of long-term debt
|
2,655
|
|
|
413
|
|
||
Long-term debt, less current maturities
|
$
|
37,853
|
|
|
$
|
36,971
|
|
•
|
$750 million
aggregate principal amount of
4.50%
senior notes due 2024
;
|
•
|
$1.50 billion
aggregate principal amount of
5.25%
senior notes due 2029
; and
|
•
|
$1.75 billion
aggregate principal amount of
6.25%
senior notes due 2049
.
|
•
|
ETO’s
$400 million
aggregate principal amount of
9.70%
senior notes due March 15, 2019
;
|
•
|
ETO’s
$450 million
aggregate principal amount of
9.00%
senior notes due April 15, 2019
; and
|
•
|
Panhandle’s
$150 million
aggregate principal amount of
8.125%
senior notes due June 1, 2019
.
|
•
|
$500 million
aggregate principal amount of
4.20%
senior notes due 2023
;
|
•
|
$1.00 billion
aggregate principal amount of
4.95%
senior notes due 2028
;
|
•
|
$500 million
aggregate principal amount of
5.80%
senior notes due 2038
; and
|
•
|
$1.00 billion
aggregate principal amount of
6.00%
senior notes due 2048
.
|
•
|
ETO’s
$650 million
aggregate principal amount of
2.50%
senior notes due June 15, 2018
;
|
•
|
Panhandle’s
$400 million
aggregate principal amount of
7.00%
senior notes due June 15, 2018
; and
|
•
|
ETO’s
$600 million
aggregate principal amount of
6.70%
senior notes due July 1, 2018
.
|
•
|
redeem in full its existing senior notes, comprised of
$800 million
in aggregate principal amount of
6.250%
senior notes due 2021,
$600 million
in aggregate principal amount of
5.500%
senior notes due 2020 and
$800 million
in aggregate principal amount of
6.375%
senior notes due 2023
;
|
•
|
repay in full and terminate its term loan
;
|
•
|
pay all closing costs in connection with its retail divestment;
|
•
|
redeem the outstanding Sunoco LP Series A Preferred Units
; and
|
•
|
repurchase
17,286,859
Sunoco LP common units owned by ETO
.
|
•
|
incur indebtedness;
|
•
|
grant liens;
|
•
|
enter into mergers;
|
•
|
dispose of assets;
|
•
|
make certain investments;
|
•
|
make Distributions (as defined in the ETO Credit Facilities) during certain Defaults (as defined in the ETO Credit Facilities) and during any Event of Default (as defined in the ETO Credit Facilities);
|
•
|
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
|
•
|
engage in transactions with affiliates; and
|
•
|
enter into restrictive agreements.
|
•
|
prohibition of certain incremental secured indebtedness;
|
•
|
prohibition of certain liens / negative pledge;
|
•
|
limitations on uses of loan proceeds;
|
•
|
limitations on asset sales and purchases;
|
•
|
limitations on permitted business activities;
|
•
|
limitations on mergers and acquisitions;
|
•
|
limitations on investments;
|
•
|
limitations on transactions with affiliates; and
|
•
|
maintenance of commercially reasonable insurance coverage.
|
•
|
grant liens;
|
•
|
make certain loans or investments;
|
•
|
incur additional indebtedness or guarantee other indebtedness;
|
•
|
merge or consolidate;
|
•
|
sell our assets; or
|
•
|
make certain acquisitions.
|
•
|
a minimum EBITDA to interest coverage ratio of
2.5
to
1.0
, determined as of the last day of each fiscal quarter; and
|
•
|
a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending March 31, 2019, (ii) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (iii) 5.0 to 1 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.
|
|
|
Payments Due by Period
|
||||||||||||||||||
Contractual Obligations
|
|
Total
|
|
Less Than 1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than 5 Years
|
||||||||||
Long-term debt
|
|
$
|
40,698
|
|
|
$
|
3,505
|
|
|
$
|
3,287
|
|
|
$
|
11,760
|
|
|
$
|
22,146
|
|
Interest on long-term debt
(1)
|
|
25,702
|
|
|
2,002
|
|
|
3,659
|
|
|
3,043
|
|
|
16,998
|
|
|||||
Payments on derivatives
|
|
181
|
|
|
76
|
|
|
105
|
|
|
—
|
|
|
—
|
|
|||||
Purchase commitments
(2)
|
|
2,458
|
|
|
2,295
|
|
|
121
|
|
|
22
|
|
|
20
|
|
|||||
Transportation, natural gas storage and fractionation contracts
|
|
9
|
|
|
8
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|||||
Operating lease obligations
|
|
601
|
|
|
104
|
|
|
169
|
|
|
108
|
|
|
220
|
|
|||||
Service concession arrangement
(3)
|
|
394
|
|
|
15
|
|
|
30
|
|
|
31
|
|
|
318
|
|
|||||
Other
(4)
|
|
198
|
|
|
26
|
|
|
51
|
|
|
43
|
|
|
78
|
|
|||||
Total
(5)
|
|
$
|
70,241
|
|
|
$
|
8,031
|
|
|
$
|
7,423
|
|
|
$
|
15,007
|
|
|
$
|
39,780
|
|
(1)
|
Interest payments on long-term debt are based on the principal amount of debt obligations as of
December 31, 2018
. With respect to variable rate debt, the interest payments were estimated using the interest rate as of
December 31, 2018
. To the extent interest rates change, our contractual obligations for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.
|
(2)
|
We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for refined product and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the
December 31, 2018
market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.
|
(3)
|
Includes minimum guaranteed payments under service concession arrangements with New Jersey Turnpike Authority and New York Thruway Authority.
|
(4)
|
Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, asset retirement obligations, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” in our consolidated balance sheets, were excluded from the table above as the amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain.
|
(5)
|
Excludes non-current deferred tax liabilities of
$2.88 billion
due to uncertainty of the timing of future cash flows for such liabilities.
|
Period Ended
|
|
Record Date
|
|
Payment Date
|
|
Series A
(1)
|
|
Series B
(1)
|
|
Series C
|
|
Series D
|
|
||||||||
December 31, 2017
|
|
February 1, 2018
|
|
February 15, 2018
|
|
$
|
15.4510
|
|
*
|
$
|
16.3780
|
|
*
|
$
|
—
|
|
|
$
|
—
|
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
31.2500
|
|
|
33.1250
|
|
|
0.5634
|
|
*
|
—
|
|
|
||||
September 30, 2018
|
|
November 1, 2018
|
|
November 15, 2018
|
|
—
|
|
|
—
|
|
|
0.4609
|
|
|
0.5931
|
|
*
|
||||
December 31, 2018
|
|
February 1, 2019
|
|
February 15, 2019
|
|
31.2500
|
|
|
33.1250
|
|
|
0.4609
|
|
|
0.4766
|
|
|
|
|
|
|
Marginal Percentage Interest in Distributions
|
||
|
|
Total Quarterly Distribution Target Amount
|
|
Common Unitholders
|
|
Holder of IDRs
|
Minimum Quarterly Distribution
|
|
$0.4375
|
|
100%
|
|
—%
|
First Target Distribution
|
|
$0.4375 to $0.503125
|
|
100%
|
|
—%
|
Second Target Distribution
|
|
$0.503125 to $0.546875
|
|
85%
|
|
15%
|
Third Target Distribution
|
|
$0.546875 to $0.656250
|
|
75%
|
|
25%
|
Thereafter
|
|
Above $0.656250
|
|
50%
|
|
50%
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2015
|
|
February 5, 2016
|
|
February 16, 2016
|
|
$
|
0.8013
|
|
March 31, 2016
|
|
May 6, 2016
|
|
May 16, 2016
|
|
0.8173
|
|
|
June 30, 2016
|
|
August 5, 2016
|
|
August 15, 2016
|
|
0.8255
|
|
|
September 30, 2016
|
|
November 7, 2016
|
|
November 15, 2016
|
|
0.8255
|
|
|
December 31, 2016
|
|
February 13, 2017
|
|
February 21, 2017
|
|
0.8255
|
|
|
March 31, 2017
|
|
May 9, 2017
|
|
May 16, 2017
|
|
0.8255
|
|
|
June 30, 2017
|
|
August 7, 2017
|
|
August 15, 2017
|
|
0.8255
|
|
|
September 30, 2017
|
|
November 7, 2017
|
|
November 14, 2017
|
|
0.8255
|
|
|
December 31, 2017
|
|
February 6, 2018
|
|
February 14, 2018
|
|
0.8255
|
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 15, 2018
|
|
0.8255
|
|
|
June 30, 2018
|
|
August 7, 2018
|
|
August 15, 2018
|
|
0.8255
|
|
|
September 30, 2018
|
|
November 6, 2018
|
|
November 14, 2018
|
|
0.8255
|
|
|
December 31, 2018
|
|
February 6, 2019
|
|
February 14, 2019
|
|
0.8255
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
March 31, 2018
|
|
May 1, 2018
|
|
May 11, 2018
|
|
$
|
0.5250
|
|
June 30, 2018
|
|
July 30, 2018
|
|
August 10, 2018
|
|
0.5250
|
|
|
September 30, 2018
|
|
October 29, 2018
|
|
November 09, 2018
|
|
0.5250
|
|
|
December 31, 2018
|
|
January 28, 2019
|
|
February 8, 2019
|
|
0.5250
|
|
•
|
a
$378 million
impairment was recorded related to the goodwill associated with the Partnership’s Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast. Additionally, the Partnership recorded asset impairments of
$4 million
related to our midstream operations and asset impairments
$9 million
related to our crude operations idle leased assets.
|
•
|
Sunoco LP also recognized a
$30 million
impairment charge on its contractual rights
primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded.
|
•
|
USAC also recognized a
$9 million
fixed asset impairment related to certain idle compressor assets.
|
•
|
a
$223 million
impairment was recorded related to the goodwill associated with CDM. In January 2018, the Partnership announced the contribution of CDM to USAC. Based on the Partnership’s anticipated proceeds in the contribution transaction, the implied fair value of the CDM reporting unit was less than the Partnership’s carrying value. As the Partnership believes that the contribution consideration also represented an appropriate estimate of fair value as of the 2017 annual impairment test date, the Partnership recorded an impairment for the difference between the carrying value and the fair value of the reporting unit. Subsequent to the impairment, a total of
$253 million
of goodwill remains in the CDM reporting unit, which amount is subject to further impairment based on changes in the contribution transaction prior to closing or any other factors affecting the fair value of the CDM reporting unit. Assuming the contribution transaction closes, the remaining CDM goodwill balance will be derecognized; if the transaction does not close, then the CDM goodwill balance will remain on the Partnership’s consolidated balance sheet and will continue to be tested for impairment in the future.
|
•
|
a
$262 million
impairment was recorded related to the goodwill associated with the Partnership’s interstate transportation and storage reporting units, and a
$229 million
impairment was recorded related to the goodwill associated with the general partner of Panhandle in the all other segment. These impairments were due to a reduction in management’s forecasted future cash flows from the related reporting units, which reduction reflected the impacts discussed in “Results of Operations” above, along with the impacts of re-contracting assumptions related to future periods.
|
•
|
a
$79 million
impairment was recorded related to the goodwill associated the Partnership’s refined products transportation and services reporting unit. Subsequent to the Sunoco Logistics Merger, the Partnership restructured the internal reporting of legacy Sunoco Logistics’ business to be consistent with the internal reporting of legacy ETO. Subsequent to this reallocation the carrying value of certain refined products reporting units was less than the estimated fair value due to a reduction in management’s forecasted future cash flows from the related reporting units, and the goodwill associated with those reporting units was fully impaired. No goodwill remained in the respective reporting units subsequent to the impairment.
|
•
|
a
$127 million
impairment of property, plant and equipment
related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets.
|
•
|
a
$141 million
impairment of the Partnership’s equity method investment in FEP. The Partnership concluded that the carrying value of its investment in FEP was other than temporarily impaired based on an anticipated decrease in production in the Fayetteville basin and a customer re-contracting with a competitor during 2017.
|
•
|
a
$172 million
impairment of the Partnership’s equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven be the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.
|
•
|
For
2017
, Sunoco LP also recognized impairments of
$404 million
, of which
$119 million
was allocated to continuing operations, as discussed further below.
|
•
|
a
$638 million
goodwill impairment and a
$133 million
impairment to property, plant and equipment were recorded in the interstate transportation and storage segment primarily due to decreases in projected future revenues and cash flows driven by changes in the markets that these assets serve.
|
•
|
a
$32 million
goodwill impairment was recorded in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices.
|
•
|
a
$308 million
impairment of the Partnership’s equity method investment in MEP. The Partnership concluded that the carrying value of its investment in MEP was other than temporarily impaired based on commercial discussions with current and potential shippers on MEP during 2016, which negatively affected the outlook for long-term transportation contract rates.
|
•
|
For
2016
, Sunoco LP also recognized impairments of
$641 million
, of which
$227 million
was allocated to continuing operations, as discussed further below.
|
•
|
the volumes transported on our pipelines and gathering systems;
|
•
|
the level of throughput in our processing and treating facilities;
|
•
|
the fees we charge and the margins we realize for our gathering, treating, processing, storage and transportation services;
|
•
|
the prices and market demand for, and the relationship between, natural gas and NGLs;
|
•
|
energy prices generally;
|
•
|
the prices of natural gas and NGLs compared to the price of alternative and competing fuels;
|
•
|
the general level of petroleum product demand and the availability and price of NGL supplies;
|
•
|
the level of domestic oil, natural gas and NGL production;
|
•
|
the availability of imported oil, natural gas and NGLs;
|
•
|
actions taken by foreign oil and gas producing nations;
|
•
|
the political and economic stability of petroleum producing nations;
|
•
|
the effect of weather conditions on demand for oil, natural gas and NGLs;
|
•
|
availability of local, intrastate and interstate transportation systems;
|
•
|
the continued ability to find and contract for new sources of natural gas supply;
|
•
|
availability and marketing of competitive fuels;
|
•
|
the impact of energy conservation efforts;
|
•
|
energy efficiencies and technological trends;
|
•
|
governmental regulation and taxation;
|
•
|
changes to, and the application of, regulation of tariff rates and operational requirements related to our interstate and intrastate pipelines;
|
•
|
hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
|
•
|
competition from other midstream companies and interstate pipeline companies;
|
•
|
loss of key personnel;
|
•
|
loss of key natural gas producers or the providers of fractionation services;
|
•
|
reductions in the capacity or allocations of third-party pipelines that connect with our pipelines and facilities;
|
•
|
the effectiveness of risk-management policies and procedures and the ability of our liquids marketing counterparties to satisfy their financial commitments;
|
•
|
the nonpayment or nonperformance by our customers;
|
•
|
regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems;
|
•
|
risks associated with the construction of new pipelines and treating and processing facilities or additions to our existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;
|
•
|
the availability and cost of capital and our ability to access certain capital sources;
|
•
|
a deterioration of the credit and capital markets;
|
•
|
risks associated with the assets and operations of entities in which we own less than a controlling interests, including risks related to management actions at such entities that we may not be able to control or exert influence;
|
•
|
the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;
|
•
|
changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and
|
•
|
the costs and effects of legal and administrative proceedings.
|
|
December 31, 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% Change
|
||||||||||
Mark-to-Market Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Swaps/Futures
|
468
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
1,078
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Basis Swaps IFERC/NYMEX
(1)
|
16,845
|
|
|
7
|
|
|
1
|
|
|
48,510
|
|
|
2
|
|
|
1
|
|
||||
Options – Puts
|
10,000
|
|
|
—
|
|
|
—
|
|
|
13,000
|
|
|
—
|
|
|
—
|
|
||||
Power (Megawatt):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Forwards
|
3,141,520
|
|
|
6
|
|
|
8
|
|
|
435,960
|
|
|
1
|
|
|
1
|
|
||||
Futures
|
56,656
|
|
|
—
|
|
|
—
|
|
|
(25,760
|
)
|
|
—
|
|
|
—
|
|
||||
Options – Puts
|
18,400
|
|
|
—
|
|
|
—
|
|
|
(153,600
|
)
|
|
—
|
|
|
1
|
|
||||
Options – Calls
|
284,800
|
|
|
1
|
|
|
—
|
|
|
137,600
|
|
|
—
|
|
|
—
|
|
||||
Crude (MBbls) – Futures
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
(Non-Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basis Swaps IFERC/NYMEX
|
(30,228
|
)
|
|
(52
|
)
|
|
13
|
|
|
4,650
|
|
|
(13
|
)
|
|
4
|
|
||||
Swing Swaps IFERC
|
54,158
|
|
|
12
|
|
|
—
|
|
|
87,253
|
|
|
(2
|
)
|
|
1
|
|
||||
Fixed Swaps/Futures
|
(1,068
|
)
|
|
19
|
|
|
1
|
|
|
(4,390
|
)
|
|
(1
|
)
|
|
2
|
|
||||
Forward Physical Contracts
|
(123,254
|
)
|
|
(1
|
)
|
|
32
|
|
|
(145,105
|
)
|
|
6
|
|
|
41
|
|
||||
NGL (MBbls) – Forwards/Swaps
|
(2,135
|
)
|
|
67
|
|
|
67
|
|
|
(2,493
|
)
|
|
5
|
|
|
16
|
|
||||
Crude (MBbls) – Forwards/Swaps
|
20,888
|
|
|
(60
|
)
|
|
29
|
|
|
9,237
|
|
|
(4
|
)
|
|
9
|
|
||||
Refined Products (MBbls) – Futures
|
(1,403
|
)
|
|
(8
|
)
|
|
6
|
|
|
(3,901
|
)
|
|
(27
|
)
|
|
4
|
|
||||
Corn (thousand bushels)
|
(1,920
|
)
|
|
—
|
|
|
1
|
|
|
1,870
|
|
|
—
|
|
|
—
|
|
||||
Fair Value Hedging Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Non-Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basis Swaps IFERC/NYMEX
|
(17,445
|
)
|
|
(4
|
)
|
|
—
|
|
|
(39,770
|
)
|
|
(2
|
)
|
|
—
|
|
||||
Fixed Swaps/Futures
|
(17,445
|
)
|
|
(10
|
)
|
|
6
|
|
|
(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.
|
Term
|
|
Type
(1)
|
|
Notional Amount Outstanding
|
||||||
December 31, 2018
|
|
December 31, 2017
|
||||||||
July 2018
(2)
|
|
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 3.56% 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
|
|
|
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 and receive a fixed rate of 1.53%
|
|
—
|
|
|
1,200
|
|
||
March 2019
|
|
Pay a floating rate 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.
|
Name
|
|
Age
|
|
|
Position with Our General Partner
|
Kelcy L. Warren
|
|
63
|
|
|
Chief Executive Officer and Chairman of the Board of Directors
|
Matthew S. Ramsey
|
|
63
|
|
|
Director, President and Chief Operating Officer
|
Thomas E. Long
|
|
62
|
|
|
Chief Financial Officer
|
Marshall S. (Mackie) McCrea, III
|
|
59
|
|
|
Director and ET President and Chief Commercial Officer
|
James M. Wright, Jr.
|
|
50
|
|
|
General Counsel
|
A. Troy Sturrock
|
|
48
|
|
|
Senior Vice President, Controller and Principal Accounting Officer
|
David K. Skidmore
|
|
63
|
|
|
Director
|
W. Brett Smith
|
|
59
|
|
|
Director
|
William P. Williams
|
|
81
|
|
|
Director
|
•
|
Kelcy L. Warren, Chairman and Chief Executive Officer;
|
•
|
Thomas E. Long, Chief Financial Officer;
|
•
|
Marshall S. (Mackie) McCrea, III, President and Chief Commercial Officer;
|
•
|
Matthew S. Ramsey, Chief Operating Officer; and
|
•
|
Thomas P. Mason, Executive Vice President, General Counsel and President — LNG.
|
•
|
reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;
|
•
|
attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size and in similar lines of business;
|
•
|
motivate executive officers and key employees to achieve strong financial and operational performance;
|
•
|
emphasize performance-based or “at-risk” compensation; and
|
•
|
reward individual performance.
|
•
|
annual base salary;
|
•
|
non-equity incentive plan compensation consisting solely of discretionary cash bonuses;
|
•
|
time-vested restricted/phantom unit awards under the equity incentive plan(s);
|
•
|
payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit awards under our equity incentive plan;
|
•
|
vesting of previously issued time-based restricted unit and/or phantom unit awards issued pursuant to ET’s equity incentive plans or the equity incentive plans(s) of affiliates; and
|
•
|
401(k) plan employer contributions.
|
Energy Peer Group:
|
|
|
• Conoco Phillips
|
|
• Anadarko Petroleum Corporation
|
• Enterprise Products Partners, L.P.
|
|
• Marathon Petroleum Corporation
|
• Plains All American Pipeline, L.P.
|
|
• Kinder Morgan, Inc.
|
• Halliburton Company
|
|
• The Williams Companies, Inc.
|
• Valero Energy Corporation
|
|
• Phillips 66
|
Name and Principal Position
|
|
Year
|
|
Salary
($)
|
|
Bonus
(1)
($)
|
|
Equity
Awards
(2)
($)
|
|
Option
Awards
($)
|
|
Non-Equity
Incentive Plan
Compensation
(3)
($)
|
|
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
|
|
All Other
Compensation
(4)
($)
|
|
Total
($)
|
||||||||||||||||
Kelcy L. Warren
(5)
|
|
2018
|
|
$
|
6,138
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6,138
|
|
Chief Executive Officer
|
|
2017
|
|
5,926
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,926
|
|
||||||||
|
2016
|
|
5,920
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
58
|
|
|
5,978
|
|
|||||||||
Thomas E. Long
|
|
2018
|
|
537,338
|
|
|
1,000,000
|
|
|
4,251,335
|
|
|
—
|
|
|
800,000
|
|
|
—
|
|
|
21,294
|
|
|
6,609,967
|
|
||||||||
Chief Financial Officer
|
|
2017
|
|
480,846
|
|
|
—
|
|
|
2,519,954
|
|
|
—
|
|
|
625,100
|
|
|
—
|
|
|
18,320
|
|
|
3,644,220
|
|
||||||||
|
2016
|
|
454,154
|
|
|
—
|
|
|
2,007,697
|
|
|
—
|
|
|
560,865
|
|
|
—
|
|
|
14,679
|
|
|
3,037,395
|
|
|||||||||
Marshall S. (Mackie) McCrea, III
|
|
2018
|
|
1,059,976
|
|
|
—
|
|
|
7,834,782
|
|
|
—
|
|
|
1,866,000
|
|
|
—
|
|
|
19,362
|
|
|
10,780,120
|
|
||||||||
President and Chief Commercial Officer
|
|
2017
|
|
1,027,846
|
|
|
—
|
|
|
9,033,341
|
|
|
—
|
|
|
1,644,554
|
|
|
—
|
|
|
16,834
|
|
|
11,722,575
|
|
||||||||
|
2016
|
|
1,009,231
|
|
|
—
|
|
|
8,059,413
|
|
|
—
|
|
|
1,533,990
|
|
|
—
|
|
|
14,818
|
|
|
10,617,452
|
|
|||||||||
Matthew S. Ramsey
|
|
2018
|
|
662,486
|
|
|
—
|
|
|
2,818,415
|
|
|
—
|
|
|
900,000
|
|
|
—
|
|
|
19,294
|
|
|
4,400,195
|
|
||||||||
Chief Operating Officer
|
|
2017
|
|
642,404
|
|
|
—
|
|
|
3,763,893
|
|
|
—
|
|
|
835,125
|
|
|
—
|
|
|
18,618
|
|
|
5,260,040
|
|
||||||||
|
2016
|
|
630,769
|
|
|
—
|
|
|
3,433,894
|
|
|
—
|
|
|
838,901
|
|
|
—
|
|
|
87,375
|
|
|
4,990,939
|
|
|||||||||
Thomas P. Mason
|
|
2018
|
|
600,477
|
|
|
—
|
|
|
2,466,882
|
|
|
—
|
|
|
858,700
|
|
|
—
|
|
|
19,294
|
|
|
3,945,353
|
|
||||||||
Executive Vice President, General Counsel and President – LNG
|
|
2017
|
|
582,275
|
|
|
—
|
|
|
2,816,048
|
|
|
—
|
|
|
756,958
|
|
|
—
|
|
|
18,618
|
|
|
4,173,899
|
|
||||||||
|
2016
|
|
571,729
|
|
|
—
|
|
|
2,524,064
|
|
|
—
|
|
|
706,067
|
|
|
—
|
|
|
14,818
|
|
|
3,816,678
|
|
(1)
|
For Mr. Long, the amount shown includes the cash portion of his Special Award.
|
(2)
|
Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. For Messrs. Long and Ramsey amounts include equity awards of our subsidiaries and/or affiliates, as reflected in the “Grants of Plan-Based Awards Table.” See Note
9
to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.
|
(3)
|
ET maintains the Bonus Plan which provides for discretionary basis. Award of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis. The discretionary cash bonus amounts earned by the named executive officers for
2018
reflect cash bonuses approved by the ET Compensation Committee in February 2019 that are expected to be paid on or before March 15, 2019.
|
(4)
|
The amounts reflected for
2018
in this column include (i) matching contributions to the ET 401(k) Plan made on behalf of the named executive officers of $13,750 each for Messrs. Long, McCrea, Ramsey and Mason, (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long and McCrea, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights were originally granted. For 2018, distribution payments in connection with distribution equivalent rights totaled $594,423 for Mr. Long, $2,183,255 for Mr. McCrea, $816,297 for Mr. Ramsey, and $759,825 for Mr. Mason.
|
(5)
|
Mr. Warren has voluntarily determined that his salary will be reduced to $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits). He also does not accept a cash bonus or any equity awards under the equity incentive plans.
|
Name
|
|
Grant Date
|
|
All Other Unit Awards: Number of Units
(#)
|
|
All Other Option Awards: Number of Securities Underlying Options
(#)
|
|
Exercise or Base Price of Option Awards
($ / Unit)
|
|
Grant Date Fair Value of Unit Awards
(1)
|
||||||
ET Unit Awards:
|
|
|
|
|
|
|
|
|
|
|
||||||
Kelcy L. Warren
|
|
N/A
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Thomas E. Long
|
|
12/18/2018
|
|
136,475
|
|
|
—
|
|
|
—
|
|
|
1,765,987
|
|
||
|
|
10/19/2018
|
|
115,200
|
|
|
(2)
|
|
|
|
1,965,312
|
|
||||
Marshal S. (Mackie) McCrea, III
|
|
12/18/2018
|
|
605,470
|
|
|
—
|
|
|
—
|
|
|
7,834,782
|
|
||
Matthew S. Ramsey
|
|
12/18/2018
|
|
168,260
|
|
|
—
|
|
|
—
|
|
|
2,177,284
|
|
||
Thomas P. Mason
|
|
12/18/2018
|
|
190,640
|
|
|
—
|
|
|
—
|
|
|
2,466,882
|
|
||
Sunoco LP Unit Awards:
|
|
|
|
|
|
|
|
|
|
|
||||||
Thomas E. Long
|
|
12/19/2018
|
|
19,325
|
|
|
—
|
|
|
—
|
|
|
520,036
|
|
||
Matthew S. Ramsey
|
|
12/19/2018
|
|
23,825
|
|
|
—
|
|
|
—
|
|
|
641,131
|
|
(1)
|
We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in
Note 8
to our consolidated financial statements.
|
(2)
|
Represents restricted units subject to Mr. Long’s Special Award.
|
Name
|
|
Grant Date
(1)
|
|
Unit Awards
(1)
|
|||||
Number of Units That Have Not Vested
(2)
(#)
|
|
Market or Payout Value of Units That Have Not Vested
(3)
($)
|
|||||||
ET Unit Awards:
|
|
|
|
|
|
|
|||
Kelcy L. Warren
|
|
N/A
|
|
—
|
|
|
$
|
—
|
|
Thomas E. Long
|
|
12/18/2018
|
|
136,475
|
|
|
1,802,835
|
|
|
|
|
10/19/2018
|
|
115,200
|
|
|
1,521,792
|
|
|
|
|
12/20/2017
|
|
121,074
|
|
|
1,599,388
|
|
|
|
|
12/29/2016
|
|
75,588
|
|
|
998,517
|
|
|
|
12/9/2015
|
|
14,227
|
|
|
187,941
|
|
|
|
|
12/4/2015
|
|
5,739
|
|
|
75,816
|
|
|
|
|
12/16/2014
|
|
10,486
|
|
|
138,520
|
|
|
Marshal S. (Mackie) McCrea, III
|
|
12/18/2018
|
|
605,740
|
|
|
8,001,825
|
|
|
|
|
12/20/2017
|
|
537,379
|
|
|
7,098,777
|
|
|
|
|
12/29/2016
|
|
430,575
|
|
|
5,687,889
|
|
|
|
|
12/9/2015
|
|
94,855
|
|
|
1,253,032
|
|
|
|
|
12/4/2015
|
|
47,816
|
|
|
631,650
|
|
|
|
|
12/16/2014
|
|
48,115
|
|
|
635,602
|
|
|
|
|
12/5/2014
|
|
21,062
|
|
|
278,231
|
|
|
Matthew S. Ramsey
|
|
12/18/2018
|
|
168,260
|
|
|
2,222,715
|
|
|
|
|
12/20/2017
|
|
223,908
|
|
|
2,957,825
|
|
|
|
|
12/29/2016
|
|
183,601
|
|
|
2,425,369
|
|
|
|
|
12/9/2015
|
|
59,282
|
|
|
783,119
|
|
|
Thomas P. Mason
|
|
12/18/2018
|
|
190,640
|
|
|
2,518,354
|
|
|
|
|
12/20/2017
|
|
135,300
|
|
|
1,787,313
|
|
|
|
|
12/29/2016
|
|
101,613
|
|
|
1,342,306
|
|
|
|
|
12/9/2015
|
|
22,391
|
|
|
295,785
|
|
|
|
|
12/4/2015
|
|
11,287
|
|
|
149,101
|
|
|
|
|
12/16/2014
|
|
16,592
|
|
|
219,181
|
|
|
|
|
12/5/2014
|
|
7,740
|
|
|
102,248
|
|
|
|
|
|
|
|
|
|
|||
Sunoco LP Unit Awards:
|
|
|
|
|
|
|
|||
Thomas E. Long
|
|
12/19/2018
|
|
19,325
|
|
|
$
|
525,447
|
|
|
|
12/21/2017
|
|
17,097
|
|
|
464,867
|
|
|
|
|
12/29/2016
|
|
22,210
|
|
|
603,890
|
|
|
|
|
12/16/2015
|
|
5,650
|
|
|
153,624
|
|
|
Matthew S. Ramsey
|
|
12/19/2018
|
|
23,825
|
|
|
647,802
|
|
|
|
|
1/2/2015
|
|
814
|
|
|
22,133
|
|
|
|
|
11/10/2014
|
|
299
|
|
|
8,130
|
|
|
Thomas P. Mason
|
|
12/21/2017
|
|
19,106
|
|
|
519,492
|
|
|
|
|
12/29/2016
|
|
7,410
|
|
|
201,483
|
|
|
|
|
12/16/2015
|
|
23,300
|
|
|
633,527
|
|
(1)
|
Certain of these outstanding awards represent Energy Transfer Partners, L.P. awards that converted into ET awards upon the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. in October 2018. Furthermore, some of those converted awards had previously been converted in connection with the merger of Energy Transfer Partners, L.P. and Sunoco Logistics in April 2017.
|
(2)
|
ET unit awards outstanding vest at a rate of 60% in December 2020 and 40% in December 2022 for awards granted in December 2017. Such awards may be settled
at the election of the ET Compensation Committee in (i) common units of ET (subject to the approval of the ET Incentive Plans prior to the first vesting date by a majority of ET’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ET Incentive Plans) of the ET common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to the Fair Market Value of ET common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ET Compensation Committee in its discretion.
|
•
|
at a rate of 60% in December 2021 and 40% in December 2023 for awards granted in October and December 2018;
|
•
|
at a rate of 60% in December 2020 and 40% in December 2022 for awards granted in December 2017;
|
•
|
at a rate of 60% in December 2019 and 40% in December 2021 for awards granted in December 2016;
|
•
|
100% in December 2020 for the remaining outstanding portion of awards granted in December 2015; and
|
•
|
100% in December 2019 for the remaining outstanding portion of all other awards.
|
(3)
|
Market value was computed as the number of unvested awards as of
December 31, 2018
multiplied by the closing price of respective common units of ET and Sunoco LP.
|
|
|
Unit Awards
|
|||||
Name
|
|
Number of Units
Acquired on Vesting
(#)
|
|
Value Realized on Vesting
($)
(1)
|
|||
ET Unit Awards:
|
|
|
|
|
|||
Kelcy L. Warren
|
|
—
|
|
|
$
|
—
|
|
Thomas E. Long
|
|
38,291
|
|
|
556,981
|
|
|
Marshall S. (Mackie) McCrea, III
|
|
295,241
|
|
|
4,294,546
|
|
|
Matthew S. Ramsey
|
|
88,923
|
|
|
1,293,474
|
|
|
Thomas P. Mason
|
|
81,949
|
|
|
1,192,030
|
|
|
Sunoco LP Unit Awards:
|
|
|
|
|
|||
Thomas E. Long
|
|
8,475
|
|
|
235,859
|
|
|
Matthew S. Ramsey
|
|
1,221
|
|
|
38,895
|
|
|
Thomas P. Mason
|
|
11,113
|
|
|
309,275
|
|
(1)
|
Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon the vesting date.
|
1.
|
It was determined that, as of December 31, 2017, the applicable employee populations consisted of 8,494 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2017 or 2018 that are required to be included in our employee population for the CEO pay ratio evaluation.
|
2.
|
To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2017 and, for 2018, updated the compensation of the “median employee” as reflected in our payroll records as reported on Form W-2 for 2018.
|
3.
|
We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee”.
|
4.
|
Once we identified our median employee, we combined all elements of the employee’s compensation for 2018 resulting in an annual compensation of $115,908. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $10,800) and the employee’s 401(k) matching contribution and profit sharing contribution
|
5.
|
With respect to Mr. Warren, we used the amount reported in the “Total” column of our 2018 Summary Compensation Table under this Item 11.
|
Name
|
|
Fees Paid in Cash
(1)
($)
|
|
Unit Awards
(2)
($)
|
|
All Other Compensation
($)
|
|
Total
($)
|
||||||||
Ted Collins, Jr.
|
|
$
|
26,223
|
|
|
$
|
100,068
|
|
|
$
|
—
|
|
|
$
|
126,291
|
|
Ray C. Davis
(3)
|
|
|
|
|
|
|
|
|
||||||||
As ET director
|
|
25,000
|
|
|
42,700
|
|
|
—
|
|
|
67,700
|
|
||||
As ETO director
|
|
49,750
|
|
|
—
|
|
|
—
|
|
|
49,750
|
|
||||
Michael K. Grimm
(4)
|
|
|
|
|
|
|
|
|
||||||||
As ET director
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
As ETO director
|
|
205,425
|
|
|
100,068
|
|
|
—
|
|
|
305,493
|
|
||||
David K. Skidmore
|
|
190,425
|
|
|
100,068
|
|
|
—
|
|
|
290,493
|
|
||||
W. Brett Smith
(5)
|
|
123,254
|
|
|
45,725
|
|
|
—
|
|
|
168,979
|
|
||||
William P. Williams
(6)
|
|
|
|
|
|
|
|
|
||||||||
As ET director
|
|
128,650
|
|
|
100,000
|
|
|
—
|
|
|
228,650
|
|
||||
As ETO director
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
Fees paid in cash are based on amounts paid during the period.
|
(2)
|
Unit award amounts reflect the aggregate grant date fair value of awards granted based on the market price of ET common units or ETO common units (prior to the Energy Transfer Merger), accordingly, as of the grant date.
|
(3)
|
Mr. Davis was appointed to the Board of Directors of our General Partner on February 6, 2018. Mr. Davis subsequently resigned from the Board of Directors of our General Partner on July 17, 2018 in order to serve on the Board of Directors of LE GP (the general partner of ET).
|
(4)
|
Mr. Grimm was appointed to the Board of Directors of LE GP on October 19, 2018. In connection with the Merger on October 19, 2018, Mr. Grimm resigned from the Board of Directors of our General Partner in order to service on the Board of Directors of LE GP (the general partner of ET).
|
(5)
|
Mr. Smith was appointed to the Board of Directors of our General Partner on February 9, 2018.
|
(6)
|
In connection with the Merger on October 19, 2018, Mr. Williams resigned from the Board of Directors of LE GP (the general partner of ET) and was appointed to the Board of Directors of our General Partner.
|
|
Years Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Audit fees
(1)
|
$
|
11.1
|
|
|
$
|
10.8
|
|
Audit related fees
(2)
|
0.5
|
|
|
—
|
|
||
Tax fees
(3)
|
0.1
|
|
|
—
|
|
||
Total
|
$
|
11.7
|
|
|
$
|
10.8
|
|
(1)
|
Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal control over financial reporting.
|
(2)
|
Includes fees in 2018 for financial statement audits of subsidiary entities in connection with contribution and sale transactions.
|
(3)
|
Includes fees in 2018 related to state and local tax consultation.
|
•
|
the auditors’ internal quality-control procedures;
|
•
|
any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
|
•
|
the independence of the external auditors;
|
•
|
the aggregate fees billed by our external auditors for each of the previous two years; and
|
•
|
the rotation of the lead partner.
|
Exhibit Number
|
|
Description
|
2.1
|
|
|
2.2
|
|
|
2.3
|
|
|
2.4
|
|
|
2.5
|
|
|
2.6
|
|
|
2.7
|
|
|
2.8
|
|
|
2.9
|
|
|
2.10
|
|
|
2.11
|
|
|
3.1
|
|
|
3.2
|
|
|
3.2.1
|
|
|
3.3
|
|
Exhibit Number
|
|
Description
|
3.3.1
|
|
|
3.4
|
|
|
3.4.1
|
|
|
3.4.2
|
|
|
3.5
|
|
|
3.5.1
|
|
|
3.6
|
|
|
3.7
|
|
|
3.8
|
|
|
3.8.1
|
|
|
4.1
|
|
|
4.2
|
|
|
4.3
|
|
|
4.4
|
|
|
4.5
|
|
|
4.6
|
|
|
4.7
|
|
|
4.8
|
|
|
4.9
|
|
|
4.10
|
|
|
4.10.1
|
|
Exhibit Number
|
|
Description
|
4.11
|
|
|
4.12
|
|
|
4.13
|
|
|
4.14
|
|
|
4.15
|
|
|
4.16
|
|
|
4.17
|
|
|
4.18
|
|
|
4.19
|
|
|
4.20
|
|
|
4.21
|
|
|
4.22
|
|
|
4.23
|
|
|
4.24
|
|
|
4.25
|
|
|
4.26
|
|
|
4.27
|
|
|
4.28
|
|
|
4.29
|
|
Exhibit Number
|
|
Description
|
4.30
|
|
|
4.31
|
|
|
4.32
|
|
|
4.33
|
|
|
4.34
|
|
|
4.35
|
|
|
4.36
|
|
|
4.37
|
|
|
10.1+
|
|
|
10.2+
|
|
|
10.3
|
|
|
10.3.1+
|
|
|
10.4
|
|
|
10.5
|
|
|
10.6
|
|
|
10.7
|
|
|
10.8
|
|
|
10.8.1
|
|
|
10.9
|
|
Exhibit Number
|
|
Description
|
10.9.1
|
|
|
10.10
|
|
|
10.12.1
|
|
|
10.13
|
|
|
10.13.1
|
|
|
10.14
|
|
|
10.15
|
|
|
10.16
|
|
|
10.17
|
|
|
10.18
|
|
|
10.19
|
|
|
10.20
|
|
|
10.21
|
|
|
10.22
|
|
|
10.23
|
|
|
10.24
|
|
|
10.25
|
|
Exhibit Number
|
|
Description
|
10.26
|
|
|
10.27
|
|
|
10.28
|
|
|
10.29
|
|
|
10.30
|
|
|
10.31
|
|
|
10.32
|
|
|
10.33
|
|
|
10.34
|
|
|
10.35
|
|
|
10.36
|
|
|
10.37
|
|
|
10.38
|
|
|
10.39
|
|
|
10.40
|
|
|
10.41
|
|
|
10.42
|
|
|
10.43
|
|
|
10.44
|
|
Exhibit Number
|
|
Description
|
10.45
|
|
|
21.1*
|
|
|
23.1*
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1**
|
|
|
32.2**
|
|
|
101*
|
|
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2018 and December 31, 2017; (ii) our Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016; (iii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016; (iv) our Consolidated Statement of Partners’ Capital for the years ended December 31, 2018, 2017 and 2016; (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016; and (vi) the notes to our Consolidated Financial Statements.
|
*
|
|
Filed herewith.
|
**
|
|
Furnished herewith.
|
+
|
|
Denotes a management contract or compensatory plan or arrangement.
|
ENERGY TRANSFER OPERATING, L.P.
|
||
|
|
|
By:
|
|
Energy Transfer Partners GP, L.P,
|
|
|
its general partner.
|
By:
|
|
Energy Transfer Partners, L.L.C.,
|
|
|
its general partner
|
|
|
|
By:
|
|
/s/ Kelcy L. Warren
|
|
|
Kelcy L. Warren
|
|
|
Chief Executive Officer and officer duly authorized to sign on behalf of the registrant
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Kelcy L. Warren
|
|
Chief Executive Officer and Chairman of the Board
|
|
February 22, 2019
|
Kelcy L. Warren
|
|
of Directors (Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Thomas E. Long
|
|
Chief Financial Officer
|
|
February 22, 2019
|
Thomas E. Long
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ A. Troy Sturrock
|
|
Senior Vice President and Controller
|
|
February 22, 2019
|
A. Troy Sturrock
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Matthew S. Ramsey
|
|
President, Chief Operating Officer and Director
|
|
February 22, 2019
|
Matthew S. Ramsey
|
|
|
|
|
|
|
|
|
|
/s/ Marshall S. McCrea, III
|
|
Chief Commercial Officer and Director
|
|
February 22, 2019
|
Marshall S. McCrea, III
|
|
|
|
|
|
|
|
|
|
/s/ David K. Skidmore
|
|
Director
|
|
February 22, 2019
|
David K. Skidmore
|
|
|
|
|
|
|
|
|
|
/s/ W. Brett Smith
|
|
Director
|
|
February 22, 2019
|
W. Brett Smith
|
|
|
|
|
|
|
|
|
|
/s/ William P. Williams
|
|
Director
|
|
February 22, 2019
|
William P. Williams
|
|
|
|
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
418
|
|
|
$
|
335
|
|
Accounts receivable, net
|
4,009
|
|
|
4,504
|
|
||
Accounts receivable from related companies
|
176
|
|
|
53
|
|
||
Inventories
|
1,677
|
|
|
2,022
|
|
||
Income taxes receivable
|
73
|
|
|
136
|
|
||
Derivative assets
|
111
|
|
|
24
|
|
||
Other current assets
|
356
|
|
|
294
|
|
||
Current assets held for sale
|
—
|
|
|
3,313
|
|
||
Total current assets
|
6,820
|
|
|
10,681
|
|
||
|
|
|
|
||||
Property, plant and equipment
|
79,280
|
|
|
70,682
|
|
||
Accumulated depreciation and depletion
|
(12,625
|
)
|
|
(9,918
|
)
|
||
|
66,655
|
|
|
60,764
|
|
||
|
|
|
|
||||
Advances to and investments in unconsolidated affiliates
|
2,636
|
|
|
2,698
|
|
||
Other non-current assets, net
|
1,006
|
|
|
879
|
|
||
Long-term affiliate receivable
|
440
|
|
|
617
|
|
||
Intangible assets, net
|
6,000
|
|
|
6,116
|
|
||
Goodwill
|
4,885
|
|
|
4,729
|
|
||
Total assets
|
$
|
88,442
|
|
|
$
|
86,484
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
3,491
|
|
|
$
|
4,685
|
|
Accounts payable to related companies
|
119
|
|
|
95
|
|
||
Derivative liabilities
|
185
|
|
|
111
|
|
||
Accrued and other current liabilities
|
2,847
|
|
|
2,512
|
|
||
Current maturities of long-term debt
|
2,655
|
|
|
413
|
|
||
Current liabilities held for sale
|
—
|
|
|
75
|
|
||
Total current liabilities
|
9,297
|
|
|
7,891
|
|
||
|
|
|
|
||||
Long-term debt, less current maturities
|
37,853
|
|
|
36,971
|
|
||
Non-current derivative liabilities
|
104
|
|
|
145
|
|
||
Deferred income taxes
|
2,884
|
|
|
3,272
|
|
||
Other non-current liabilities
|
1,184
|
|
|
1,217
|
|
||
|
|
|
|
||||
Commitments and contingencies
|
|
|
|
||||
Redeemable noncontrolling interests
|
499
|
|
|
21
|
|
||
|
|
|
|
||||
Equity:
|
|
|
|
||||
Limited Partners:
|
|
|
|
||||
Series A Preferred Unitholders (950,000 units authorized, issued and outstanding as of December 31, 2018 and 2017, respectively)
|
958
|
|
|
944
|
|
||
Series B Preferred Unitholders (550,000 units authorized, issued and outstanding as of December 31, 2018 and 2017, respectively)
|
556
|
|
|
547
|
|
||
Series C Preferred Unitholders (18,000,000 units authorized, issued and outstanding as of December 31, 2018)
|
440
|
|
|
—
|
|
||
Series D Preferred Unitholders (17,800,000 units authorized, issued and outstanding as of December 31, 2018)
|
434
|
|
|
—
|
|
||
Common Unitholders and Other
|
26,372
|
|
|
26,531
|
|
||
General Partner
|
—
|
|
|
244
|
|
||
Accumulated other comprehensive income (loss)
|
(42
|
)
|
|
3
|
|
||
Total partners’ capital
|
28,718
|
|
|
28,269
|
|
||
Noncontrolling interest
|
7,903
|
|
|
5,882
|
|
||
Predecessor equity
|
—
|
|
|
2,816
|
|
||
Total equity
|
36,621
|
|
|
36,967
|
|
||
Total liabilities and equity
|
$
|
88,442
|
|
|
$
|
86,484
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
REVENUES:
|
|
|
|
|
|
||||||
Refined product sales
|
$
|
18,345
|
|
|
$
|
11,975
|
|
|
$
|
10,097
|
|
Crude sales
|
14,415
|
|
|
10,706
|
|
|
7,205
|
|
|||
NGL sales
|
9,109
|
|
|
6,972
|
|
|
4,841
|
|
|||
Gathering, transportation and other fees
|
6,797
|
|
|
4,435
|
|
|
4,172
|
|
|||
Natural gas sales
|
4,452
|
|
|
4,172
|
|
|
3,619
|
|
|||
Other
|
969
|
|
|
2,263
|
|
|
1,858
|
|
|||
Total revenues
|
54,087
|
|
|
40,523
|
|
|
31,792
|
|
|||
COSTS AND EXPENSES:
|
|
|
|
|
|
||||||
Cost of products sold
|
41,658
|
|
|
30,966
|
|
|
23,693
|
|
|||
Operating expenses
|
3,089
|
|
|
2,644
|
|
|
2,336
|
|
|||
Depreciation, depletion and amortization
|
2,843
|
|
|
2,541
|
|
|
2,201
|
|
|||
Selling, general and administrative
|
664
|
|
|
568
|
|
|
547
|
|
|||
Impairment losses
|
431
|
|
|
1,039
|
|
|
1,040
|
|
|||
Total costs and expenses
|
48,685
|
|
|
37,758
|
|
|
29,817
|
|
|||
OPERATING INCOME
|
5,402
|
|
|
2,765
|
|
|
1,975
|
|
|||
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
||||||
Interest expense, net
|
(1,709
|
)
|
|
(1,575
|
)
|
|
(1,478
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
344
|
|
|
144
|
|
|
270
|
|
|||
Impairment of investments in unconsolidated affiliates
|
—
|
|
|
(313
|
)
|
|
(308
|
)
|
|||
Gains on acquisitions
|
—
|
|
|
—
|
|
|
83
|
|
|||
Losses on extinguishments of debt
|
(109
|
)
|
|
(42
|
)
|
|
—
|
|
|||
Gains (losses) on interest rate derivatives
|
47
|
|
|
(37
|
)
|
|
(12
|
)
|
|||
Other, net
|
69
|
|
|
206
|
|
|
126
|
|
|||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)
|
4,044
|
|
|
1,148
|
|
|
656
|
|
|||
Income tax expense (benefit) from continuing operations
|
5
|
|
|
(1,804
|
)
|
|
(255
|
)
|
|||
INCOME FROM CONTINUING OPERATIONS
|
4,039
|
|
|
2,952
|
|
|
911
|
|
|||
Loss from discontinued operations
|
(265
|
)
|
|
(177
|
)
|
|
(462
|
)
|
|||
NET INCOME
|
3,774
|
|
|
2,775
|
|
|
449
|
|
|||
Less: Net income attributable to noncontrolling interest
|
715
|
|
|
420
|
|
|
295
|
|
|||
Less: Net income attributable to redeemable noncontrolling interest
|
39
|
|
|
—
|
|
|
—
|
|
|||
Less: Net income (loss) attributable to predecessor
|
(5
|
)
|
|
274
|
|
|
(134
|
)
|
|||
NET INCOME ATTRIBUTABLE TO PARTNERS
|
$
|
3,025
|
|
|
$
|
2,081
|
|
|
$
|
288
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Net income
|
$
|
3,774
|
|
|
$
|
2,775
|
|
|
$
|
449
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
||||||
Change in value of available-for-sale securities
|
(4
|
)
|
|
6
|
|
|
2
|
|
|||
Actuarial loss relating to pension and other postretirement benefits
|
(43
|
)
|
|
(12
|
)
|
|
(1
|
)
|
|||
Foreign currency translation adjustment
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||
Change in other comprehensive income from unconsolidated affiliates
|
4
|
|
|
1
|
|
|
4
|
|
|||
|
(43
|
)
|
|
(5
|
)
|
|
4
|
|
|||
Comprehensive income
|
3,731
|
|
|
2,770
|
|
|
453
|
|
|||
Less: Comprehensive income attributable to noncontrolling interest
|
715
|
|
|
420
|
|
|
295
|
|
|||
Less: Comprehensive income attributable to redeemable noncontrolling interest
|
39
|
|
|
—
|
|
|
—
|
|
|||
Less: Comprehensive income (loss) attributable to predecessor
|
(5
|
)
|
|
274
|
|
|
(134
|
)
|
|||
Comprehensive income attributable to partners
|
$
|
2,982
|
|
|
$
|
2,076
|
|
|
$
|
292
|
|
|
Limited Partners
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||
|
Series A Preferred Units
|
|
Series B Preferred Units
|
|
Series C Preferred Units
|
|
Series D Preferred Units
|
|
Common Units and Other
|
|
General
Partner |
|
AOCI
|
|
Non-controlling
Interest
|
|
Predecessor Equity
|
|
Total
|
||||||||||||||||||||
Balance, December 31, 2015
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
20,514
|
|
|
$
|
306
|
|
|
$
|
4
|
|
|
$
|
6,162
|
|
|
$
|
2,982
|
|
|
$
|
29,968
|
|
Distributions to partners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,494
|
)
|
|
(1,048
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,542
|
)
|
||||||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(481
|
)
|
|
(245
|
)
|
|
(726
|
)
|
||||||||||
Partnership units issued for cash
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,098
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,098
|
|
||||||||||
Subsidiary units issued for cash
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37
|
|
|
—
|
|
|
—
|
|
|
1,351
|
|
|
132
|
|
|
1,520
|
|
||||||||||
Capital contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
236
|
|
|
—
|
|
|
236
|
|
||||||||||
Sunoco, Inc. retail business to Sunoco LP transaction
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(405
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(374
|
)
|
|
(779
|
)
|
||||||||||
PennTex Acquisition
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
307
|
|
|
—
|
|
|
—
|
|
|
236
|
|
|
—
|
|
|
543
|
|
||||||||||
Deemed contribution from parent
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
75
|
|
|
75
|
|
||||||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||||||||
Other, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
61
|
|
|
92
|
|
||||||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(660
|
)
|
|
948
|
|
|
—
|
|
|
295
|
|
|
(134
|
)
|
|
449
|
|
||||||||||
Balance, December 31, 2016
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,407
|
|
|
206
|
|
|
8
|
|
|
7,820
|
|
|
2,497
|
|
|
28,938
|
|
||||||||||
Distributions to partners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,516
|
)
|
|
(952
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,468
|
)
|
||||||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(430
|
)
|
|
(284
|
)
|
|
(714
|
)
|
||||||||||
Partnership units issued for cash
|
937
|
|
|
542
|
|
|
—
|
|
|
—
|
|
|
2,283
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,762
|
|
||||||||||
Subsidiary units issued for cash
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
333
|
|
|
333
|
|
||||||||||
Sunoco Logistics Merger
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,938
|
|
|
—
|
|
|
—
|
|
|
(5,938
|
)
|
|
—
|
|
|
—
|
|
||||||||||
Capital contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,202
|
|
|
—
|
|
|
2,202
|
|
||||||||||
Sale of Bakken pipeline interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,260
|
|
|
—
|
|
|
—
|
|
|
740
|
|
|
—
|
|
|
2,000
|
|
||||||||||
Sale of Rover pipeline interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
93
|
|
|
—
|
|
|
—
|
|
|
1,385
|
|
|
—
|
|
|
1,478
|
|
||||||||||
Acquisition of PennTex noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(48
|
)
|
|
—
|
|
|
—
|
|
|
(232
|
)
|
|
—
|
|
|
(280
|
)
|
||||||||||
Other comprehensive loss, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
||||||||||
Other, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
35
|
|
|
—
|
|
|
—
|
|
|
(85
|
)
|
|
(4
|
)
|
|
(54
|
)
|
||||||||||
Net income
|
7
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
1,079
|
|
|
990
|
|
|
—
|
|
|
420
|
|
|
274
|
|
|
2,775
|
|
||||||||||
Balance, December 31, 2017
|
944
|
|
|
547
|
|
|
—
|
|
|
—
|
|
|
26,531
|
|
|
244
|
|
|
3
|
|
|
5,882
|
|
|
2,816
|
|
|
36,967
|
|
||||||||||
Distributions to partners
|
(44
|
)
|
|
(27
|
)
|
|
(18
|
)
|
|
(11
|
)
|
|
(3,376
|
)
|
|
(1,080
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,556
|
)
|
||||||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(891
|
)
|
|
(276
|
)
|
|
(1,167
|
)
|
||||||||||
Partnership units issued for cash
|
—
|
|
|
—
|
|
|
436
|
|
|
431
|
|
|
58
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
925
|
|
||||||||||
Subsidiary units issued for cash
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||||
Subsidiary units repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(300
|
)
|
|
(300
|
)
|
||||||||||
Energy Transfer Merger
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,370
|
|
|
(340
|
)
|
|
—
|
|
|
1,474
|
|
|
(2,504
|
)
|
|
—
|
|
||||||||||
Capital contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
649
|
|
|
—
|
|
|
649
|
|
||||||||||
Cumulative effect adjustment due to change in accounting principle
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(54
|
)
|
|
(54
|
)
|
||||||||||
Deemed distribution, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37
|
|
|
—
|
|
|
—
|
|
|
58
|
|
|
(497
|
)
|
|
(402
|
)
|
||||||||||
Acquisition of USAC
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
832
|
|
|
832
|
|
Other comprehensive loss, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(43
|
)
|
|
—
|
|
|
—
|
|
|
(43
|
)
|
||||||||||
Other, net
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|
53
|
|
|
(17
|
)
|
|
(2
|
)
|
|
16
|
|
|
(12
|
)
|
|
35
|
|
||||||||||
Net income (loss), excluding amounts attributable to redeemable interests
|
59
|
|
|
36
|
|
|
23
|
|
|
15
|
|
|
1,699
|
|
|
1,193
|
|
|
—
|
|
|
715
|
|
|
(5
|
)
|
|
3,735
|
|
||||||||||
Balance, December 31, 2018
|
$
|
958
|
|
|
$
|
556
|
|
|
$
|
440
|
|
|
$
|
434
|
|
|
$
|
26,372
|
|
|
$
|
—
|
|
|
$
|
(42
|
)
|
|
$
|
7,903
|
|
|
$
|
—
|
|
|
$
|
36,621
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
OPERATING ACTIVITIES:
|
|
|
|
|
|
||||||
Net income
|
$
|
3,774
|
|
|
$
|
2,775
|
|
|
$
|
449
|
|
Reconciliation of net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Loss from discontinued operations
|
265
|
|
|
177
|
|
|
462
|
|
|||
Depreciation, depletion and amortization
|
2,843
|
|
|
2,541
|
|
|
2,201
|
|
|||
Deferred income taxes
|
(8
|
)
|
|
(1,841
|
)
|
|
(174
|
)
|
|||
Inventory valuation adjustments
|
85
|
|
|
(24
|
)
|
|
(97
|
)
|
|||
Non-cash compensation expense
|
105
|
|
|
99
|
|
|
93
|
|
|||
Impairment losses
|
431
|
|
|
1,039
|
|
|
1,040
|
|
|||
Impairment of investments in unconsolidated affiliates
|
—
|
|
|
313
|
|
|
308
|
|
|||
Gains on acquisitions
|
—
|
|
|
—
|
|
|
(83
|
)
|
|||
Losses on extinguishments of debt
|
109
|
|
|
42
|
|
|
—
|
|
|||
Distributions on unvested awards
|
(33
|
)
|
|
(35
|
)
|
|
(29
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
(344
|
)
|
|
(144
|
)
|
|
(270
|
)
|
|||
Distributions from unconsolidated affiliates
|
328
|
|
|
297
|
|
|
268
|
|
|||
Other non-cash
|
(113
|
)
|
|
(249
|
)
|
|
(265
|
)
|
|||
Net change in operating assets and liabilities, net of effects of acquisitions
|
117
|
|
|
(173
|
)
|
|
303
|
|
|||
Net cash provided by operating activities
|
7,559
|
|
|
4,817
|
|
|
4,206
|
|
|||
INVESTING ACTIVITIES:
|
|
|
|
|
|
||||||
Cash proceeds from USAC Acquisition, net
|
711
|
|
|
—
|
|
|
—
|
|
|||
Cash proceeds from Bakken pipeline transaction
|
—
|
|
|
2,000
|
|
|
—
|
|
|||
Cash proceeds from Rover pipeline transaction
|
—
|
|
|
1,478
|
|
|
—
|
|
|||
Cash paid for acquisition of PennTex noncontrolling interest
|
—
|
|
|
(280
|
)
|
|
—
|
|
|||
Cash paid for Vitol Acquisition, net of cash received
|
—
|
|
|
—
|
|
|
(769
|
)
|
|||
Cash paid for PennTex Acquisition, net of cash received
|
—
|
|
|
—
|
|
|
(299
|
)
|
|||
Cash paid for all other acquisitions
|
(429
|
)
|
|
(303
|
)
|
|
(330
|
)
|
|||
Capital expenditures, excluding allowance for equity funds used during construction
|
(7,407
|
)
|
|
(8,444
|
)
|
|
(7,755
|
)
|
|||
Contributions in aid of construction costs
|
109
|
|
|
24
|
|
|
71
|
|
|||
Contributions to unconsolidated affiliates
|
(26
|
)
|
|
(268
|
)
|
|
(59
|
)
|
|||
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
69
|
|
|
135
|
|
|
135
|
|
|||
Proceeds from the sale of assets
|
87
|
|
|
45
|
|
|
35
|
|
|||
Change in restricted cash
|
—
|
|
|
—
|
|
|
14
|
|
|||
Other
|
(16
|
)
|
|
1
|
|
|
—
|
|
|||
Net cash used in investing activities
|
(6,902
|
)
|
|
(5,612
|
)
|
|
(8,957
|
)
|
|||
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
||||||
Proceeds from borrowings
|
28,538
|
|
|
29,389
|
|
|
25,560
|
|
|||
Repayments of debt
|
(27,297
|
)
|
|
(29,387
|
)
|
|
(18,866
|
)
|
|||
Cash paid to affiliate notes
|
(440
|
)
|
|
(423
|
)
|
|
(288
|
)
|
|||
Common units issued for cash
|
58
|
|
|
2,283
|
|
|
1,098
|
|
|||
Preferred units issued for cash
|
867
|
|
|
1,479
|
|
|
—
|
|
|||
Redeemable noncontrolling interest issued for cash
|
465
|
|
|
—
|
|
|
—
|
|
|||
Subsidiary units issued for cash
|
—
|
|
|
—
|
|
|
1,388
|
|
|||
Predecessor units issued for cash
|
—
|
|
|
333
|
|
|
132
|
|
|||
Capital contributions from noncontrolling interest
|
649
|
|
|
1,214
|
|
|
236
|
|
|||
Distributions to partners
|
(4,556
|
)
|
|
(3,468
|
)
|
|
(3,542
|
)
|
|||
Predecessor distributions to partners
|
(276
|
)
|
|
(284
|
)
|
|
(245
|
)
|
|||
Distributions to noncontrolling interest
|
(891
|
)
|
|
(430
|
)
|
|
(481
|
)
|
|||
Distributions to redeemable noncontrolling interest
|
(24
|
)
|
|
—
|
|
|
—
|
|
|||
Repurchases of common units
|
(24
|
)
|
|
—
|
|
|
—
|
|
|||
Subsidiary repurchases of common units
|
(300
|
)
|
|
—
|
|
|
—
|
|
|||
Redemption of Legacy ETP Preferred Units
|
—
|
|
|
(53
|
)
|
|
—
|
|
|||
Debt issuance costs
|
(162
|
)
|
|
(83
|
)
|
|
(52
|
)
|
|||
Deemed contribution from parent
|
—
|
|
|
—
|
|
|
75
|
|
|||
Other
|
85
|
|
|
2
|
|
|
2
|
|
|||
Net cash provided by (used in) financing activities
|
(3,308
|
)
|
|
572
|
|
|
5,017
|
|
|||
DISCONTINUED OPERATIONS:
|
|
|
|
|
|
||||||
Operating activities
|
(484
|
)
|
|
136
|
|
|
93
|
|
|||
Investing activities
|
3,207
|
|
|
(38
|
)
|
|
(483
|
)
|
|||
Changes in cash included in current assets held for sale
|
11
|
|
|
(5
|
)
|
|
5
|
|
|||
Net increase (decrease) in cash and cash equivalents of discontinued operations
|
2,734
|
|
|
93
|
|
|
(385
|
)
|
|||
Increase (decrease) in cash and cash equivalents
|
83
|
|
|
(130
|
)
|
|
(119
|
)
|
|||
Cash and cash equivalents, beginning of period
|
335
|
|
|
465
|
|
|
584
|
|
|||
Cash and cash equivalents, end of period
|
$
|
418
|
|
|
$
|
335
|
|
|
$
|
465
|
|
1.
|
OPERATIONS AND BASIS OF PRESENTATION:
|
•
|
the IDRs in ETO were converted into
1,168,205,710
ETO common units; and
|
•
|
the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued
18,448,341
ETO common units to ETP GP.
|
•
|
References to “ETO” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer Operating, L.P. subsequent to the close of the Energy Transfer Merger; and
|
•
|
References to “ET” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer LP subsequent to the close of the Energy Transfer Merger.
|
•
|
References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. and its subsidiaries prior to the close of the Sunoco Logistics Merger; and
|
•
|
References to “ETO” for periods prior to the Sunoco Logistics Merger refer to the consolidated entity named Energy Transfer Partners, L.P. and its subsidiaries prior to the close of the Sunoco Logistics Merger.
|
2.
|
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
|
|
Balance at December 31, 2017
|
|
Adjustments due to ASC 606
|
|
Balance at January 1, 2018
|
||||||
Assets:
|
|
|
|
|
|
||||||
Other current assets
|
$
|
294
|
|
|
$
|
8
|
|
|
$
|
302
|
|
Property, plant and equipment, net
|
60,764
|
|
|
—
|
|
|
60,764
|
|
|||
Intangible assets, net
|
6,116
|
|
|
(100
|
)
|
|
6,016
|
|
|||
Other non-current assets, net
|
879
|
|
|
39
|
|
|
918
|
|
|||
|
|
|
|
|
|
||||||
Liabilities and Equity:
|
|
|
|
|
|
||||||
Other non-current liabilities
|
$
|
1,217
|
|
|
$
|
1
|
|
|
$
|
1,218
|
|
Noncontrolling interest
|
5,882
|
|
|
(54
|
)
|
|
5,828
|
|
|
Year Ended December 31, 2018
|
||||||||||
|
As Reported
|
|
Balances Without Adoption of ASC 606
|
|
Effect of Change: Higher/(Lower)
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Natural gas sales
|
$
|
4,452
|
|
|
$
|
4,452
|
|
|
$
|
—
|
|
NGL sales
|
9,109
|
|
|
9,071
|
|
|
38
|
|
|||
Crude sales
|
14,415
|
|
|
14,403
|
|
|
12
|
|
|||
Gathering, transportation and other fees
|
6,797
|
|
|
7,526
|
|
|
(729
|
)
|
|||
Refined product sales
|
18,345
|
|
|
18,393
|
|
|
(48
|
)
|
|||
Other
|
969
|
|
|
968
|
|
|
1
|
|
|||
|
|
|
|
|
|
||||||
Costs and expenses:
|
|
|
|
|
|
||||||
Cost of products sold
|
$
|
41,658
|
|
|
$
|
42,389
|
|
|
$
|
(731
|
)
|
Operating expenses
|
3,089
|
|
|
3,045
|
|
|
44
|
|
|||
Depreciation and amortization
|
2,843
|
|
|
2,872
|
|
|
(29
|
)
|
|
Year Ended December 31, 2018
|
||||||||||
|
As Reported
|
|
Balances Without Adoption of ASC 606
|
|
Effect of Change: Higher/(Lower)
|
||||||
Assets:
|
|
|
|
|
|
||||||
Other current assets
|
$
|
356
|
|
|
$
|
344
|
|
|
$
|
12
|
|
Property, plant and equipment, net
|
66,655
|
|
|
66,655
|
|
|
—
|
|
|||
Intangible assets, net
|
6,000
|
|
|
6,134
|
|
|
(134
|
)
|
|||
Other non-current assets, net
|
1,006
|
|
|
947
|
|
|
59
|
|
|||
|
|
|
|
|
|
||||||
Liabilities and Equity:
|
|
|
|
|
|
||||||
Other non-current liabilities
|
$
|
1,184
|
|
|
$
|
1,183
|
|
|
$
|
1
|
|
Noncontrolling interest
|
7,903
|
|
|
7,967
|
|
|
(64
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Accounts receivable
|
$
|
506
|
|
|
$
|
(951
|
)
|
|
$
|
(1,114
|
)
|
Accounts receivable from related companies
|
128
|
|
|
(462
|
)
|
|
427
|
|
|||
Inventories
|
282
|
|
|
58
|
|
|
(485
|
)
|
|||
Other current assets
|
7
|
|
|
40
|
|
|
146
|
|
|||
Other non-current assets, net
|
(109
|
)
|
|
(88
|
)
|
|
(146
|
)
|
|||
Accounts payable
|
(769
|
)
|
|
713
|
|
|
1,145
|
|
|||
Accounts payable to related companies
|
(206
|
)
|
|
486
|
|
|
319
|
|
|||
Accrued and other current liabilities
|
365
|
|
|
(56
|
)
|
|
71
|
|
|||
Other non-current liabilities
|
(34
|
)
|
|
78
|
|
|
(127
|
)
|
|||
Price risk management assets and liabilities, net
|
(53
|
)
|
|
9
|
|
|
67
|
|
|||
Net change in operating assets and liabilities, net of effects of acquisitions
|
$
|
117
|
|
|
$
|
(173
|
)
|
|
$
|
303
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
NON-CASH INVESTING ACTIVITIES:
|
|
|
|
|
|
||||||
Accrued capital expenditures
|
$
|
1,030
|
|
|
$
|
1,060
|
|
|
$
|
848
|
|
Net gains (losses) from subsidiary common unit transactions
|
(127
|
)
|
|
5
|
|
|
8
|
|
|||
NON-CASH FINANCING ACTIVITIES:
|
|
|
|
|
|
||||||
Issuance of Common Units in connection with the PennTex Acquisition
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
307
|
|
Contribution of assets from noncontrolling interest
|
—
|
|
|
988
|
|
|
—
|
|
|||
SUPPLEMENTAL CASH FLOW INFORMATION:
|
|
|
|
|
|
||||||
Cash paid for interest, net of interest capitalized
|
$
|
1,537
|
|
|
$
|
1,516
|
|
|
$
|
1,507
|
|
Cash paid for (refund of) income taxes
|
508
|
|
|
50
|
|
|
(229
|
)
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Natural gas, NGLs and refined products
(1)
|
$
|
833
|
|
|
$
|
1,120
|
|
Crude oil
|
506
|
|
|
551
|
|
||
Spare parts and other
|
338
|
|
|
351
|
|
||
Total inventories
|
$
|
1,677
|
|
|
$
|
2,022
|
|
(1)
|
Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of
$85 million
as of
December 31, 2018
.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Deposits paid to vendors
|
$
|
141
|
|
|
$
|
64
|
|
Prepaid expenses and other
|
215
|
|
|
230
|
|
||
Total other current assets
|
$
|
356
|
|
|
$
|
294
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Land and improvements
|
$
|
2,146
|
|
|
$
|
2,222
|
|
Buildings and improvements (1 to 45 years)
|
2,636
|
|
|
2,786
|
|
||
Pipelines and equipment (5 to 83 years)
|
57,584
|
|
|
44,673
|
|
||
Natural gas and NGL storage facilities (5 to 46 years)
|
1,898
|
|
|
1,681
|
|
||
Bulk storage, equipment and facilities (2 to 83 years)
|
3,395
|
|
|
3,036
|
|
||
Tanks and other equipment (5 to 40 years)
|
884
|
|
|
847
|
|
||
Vehicles (1 to 25 years)
|
123
|
|
|
126
|
|
||
Right of way (20 to 83 years)
|
3,555
|
|
|
3,432
|
|
||
Natural resources
|
434
|
|
|
434
|
|
||
Other (1 to 40 years)
|
558
|
|
|
534
|
|
||
Construction work-in-process
|
6,067
|
|
|
10,911
|
|
||
Property, plant and equipment, gross
|
79,280
|
|
|
70,682
|
|
||
Less: Accumulated depreciation and depletion
|
(12,625
|
)
|
|
(9,918
|
)
|
||
Property, plant and equipment, net
|
$
|
66,655
|
|
|
$
|
60,764
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Depreciation, depletion and amortization expense
|
$
|
2,522
|
|
|
$
|
2,199
|
|
|
$
|
1,940
|
|
Capitalized interest
|
294
|
|
|
286
|
|
|
201
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Regulatory assets
|
$
|
43
|
|
|
$
|
85
|
|
Deferred charges
|
241
|
|
|
210
|
|
||
Restricted funds
|
178
|
|
|
192
|
|
||
Other
|
544
|
|
|
392
|
|
||
Total other non-current assets, net
|
$
|
1,006
|
|
|
$
|
879
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Gross Carrying
Amount
|
|
Accumulated
Amortization
|
|
Gross Carrying
Amount
|
|
Accumulated
Amortization
|
||||||||
Amortizable intangible assets:
|
|
|
|
|
|
|
|
||||||||
Customer relationships, contracts and agreements (3 to 46 years)
|
$
|
7,106
|
|
|
$
|
(1,493
|
)
|
|
$
|
6,979
|
|
|
$
|
(1,277
|
)
|
Patents (10 years)
|
48
|
|
|
(30
|
)
|
|
48
|
|
|
(26
|
)
|
||||
Trade Names (20 years)
|
66
|
|
|
(28
|
)
|
|
66
|
|
|
(25
|
)
|
||||
Other (5 to 20 years)
|
33
|
|
|
(9
|
)
|
|
28
|
|
|
(14
|
)
|
||||
Total amortizable intangible assets
|
7,253
|
|
|
(1,560
|
)
|
|
7,121
|
|
|
(1,342
|
)
|
||||
Non-amortizable intangible assets:
|
|
|
|
|
|
|
|
||||||||
Trademarks
|
295
|
|
|
—
|
|
|
295
|
|
|
—
|
|
||||
Other
|
12
|
|
|
—
|
|
|
42
|
|
|
—
|
|
||||
Total non-amortizable intangible assets
|
307
|
|
|
—
|
|
|
337
|
|
|
—
|
|
||||
Total intangible assets
|
$
|
7,560
|
|
|
$
|
(1,560
|
)
|
|
$
|
7,458
|
|
|
$
|
(1,342
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Reported in depreciation, depletion and amortization expense
|
$
|
321
|
|
|
$
|
336
|
|
|
$
|
257
|
|
|
Intrastate
Transportation
and Storage
|
|
Interstate
Transportation and Storage
|
|
Midstream
|
|
NGL and Refined Products Transportation and Services
|
|
Crude Oil Transportation and Services
|
|
Investment in Sunoco LP
|
|
Investment in USAC
|
|
All Other
|
|
Total
|
||||||||||||||||||
Balance, December 31, 2016
|
$
|
10
|
|
|
$
|
458
|
|
|
$
|
863
|
|
|
$
|
772
|
|
|
$
|
1,163
|
|
|
$
|
1,550
|
|
|
$
|
—
|
|
|
$
|
815
|
|
|
$
|
5,631
|
|
Acquired
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|||||||||
Impaired
|
—
|
|
|
(262
|
)
|
|
—
|
|
|
(79
|
)
|
|
—
|
|
|
(102
|
)
|
|
—
|
|
|
(452
|
)
|
|
(895
|
)
|
|||||||||
Other
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
—
|
|
|
(19
|
)
|
|||||||||
Balance, December 31, 2017
|
10
|
|
|
196
|
|
|
870
|
|
|
693
|
|
|
1,167
|
|
|
1,430
|
|
|
—
|
|
|
363
|
|
|
4,729
|
|
|||||||||
Acquired
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
129
|
|
|
366
|
|
|
—
|
|
|
495
|
|
|||||||||
CDM Contribution
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
253
|
|
|
(253
|
)
|
|
—
|
|
|||||||||
Impaired
|
—
|
|
|
—
|
|
|
(378
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(378
|
)
|
|||||||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
39
|
|
|
39
|
|
|||||||||
Balance, December 31, 2018
|
$
|
10
|
|
|
$
|
196
|
|
|
$
|
492
|
|
|
$
|
693
|
|
|
$
|
1,167
|
|
|
$
|
1,559
|
|
|
$
|
619
|
|
|
$
|
149
|
|
|
$
|
4,885
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Interest payable
|
$
|
503
|
|
|
$
|
486
|
|
Customer advances and deposits
|
128
|
|
|
75
|
|
||
Accrued capital expenditures
|
1,030
|
|
|
1,006
|
|
||
Accrued wages and benefits
|
283
|
|
|
280
|
|
||
Taxes payable other than income taxes
|
256
|
|
|
288
|
|
||
Exchanges payable
|
112
|
|
|
154
|
|
||
Other
|
535
|
|
|
223
|
|
||
Total accrued and other current liabilities
|
$
|
2,847
|
|
|
$
|
2,512
|
|
|
Fair Value Total
|
|
Fair Value Measurements at December 31, 2018
|
||||||||
|
Level 1
|
|
Level 2
|
||||||||
Assets:
|
|
|
|
|
|
||||||
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
$
|
42
|
|
|
$
|
42
|
|
|
$
|
—
|
|
Swing Swaps IFERC
|
52
|
|
|
8
|
|
|
44
|
|
|||
Fixed Swaps/Futures
|
97
|
|
|
97
|
|
|
—
|
|
|||
Forward Physical Contracts
|
20
|
|
|
—
|
|
|
20
|
|
|||
Power:
|
|
|
|
|
|
||||||
Forwards
|
48
|
|
|
—
|
|
|
48
|
|
|||
Futures
|
1
|
|
|
1
|
|
|
—
|
|
|||
Options – Calls
|
1
|
|
|
1
|
|
|
—
|
|
|||
NGLs – Forwards/Swaps
|
291
|
|
|
291
|
|
|
—
|
|
|||
Refined Products – Futures
|
7
|
|
|
7
|
|
|
—
|
|
|||
Crude – Forwards/Swaps
|
1
|
|
|
1
|
|
|
—
|
|
|||
Total commodity derivatives
|
560
|
|
|
448
|
|
|
112
|
|
|||
Other non-current assets
|
26
|
|
|
17
|
|
|
9
|
|
|||
Total assets
|
$
|
586
|
|
|
$
|
465
|
|
|
$
|
121
|
|
Liabilities:
|
|
|
|
|
|
||||||
Interest rate derivatives
|
$
|
(163
|
)
|
|
$
|
—
|
|
|
$
|
(163
|
)
|
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
(91
|
)
|
|
(91
|
)
|
|
—
|
|
|||
Swing Swaps IFERC
|
(40
|
)
|
|
—
|
|
|
(40
|
)
|
|||
Fixed Swaps/Futures
|
(88
|
)
|
|
(88
|
)
|
|
—
|
|
|||
Forward Physical Contracts
|
(21
|
)
|
|
—
|
|
|
(21
|
)
|
|||
Power:
|
|
|
|
|
|
||||||
Forwards
|
(42
|
)
|
|
—
|
|
|
(42
|
)
|
|||
Futures
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|||
NGLs – Forwards/Swaps
|
(224
|
)
|
|
(224
|
)
|
|
—
|
|
|||
Refined Products – Futures
|
(15
|
)
|
|
(15
|
)
|
|
—
|
|
|||
Crude – Forwards/Swaps
|
(61
|
)
|
|
(61
|
)
|
|
—
|
|
|||
Total commodity derivatives
|
(583
|
)
|
|
(480
|
)
|
|
(103
|
)
|
|||
Total liabilities
|
$
|
(746
|
)
|
|
$
|
(480
|
)
|
|
$
|
(266
|
)
|
|
Fair Value Total
|
|
Fair Value Measurements at December 31, 2017
|
||||||||
|
Level 1
|
|
Level 2
|
||||||||
Assets:
|
|
|
|
|
|
||||||
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
—
|
|
Swing Swaps IFERC
|
13
|
|
|
—
|
|
|
13
|
|
|||
Fixed Swaps/Futures
|
70
|
|
|
70
|
|
|
—
|
|
|||
Forward Physical Contracts
|
8
|
|
|
—
|
|
|
8
|
|
|||
Power – Forwards
|
23
|
|
|
—
|
|
|
23
|
|
|||
NGLs – Forwards/Swaps
|
191
|
|
|
191
|
|
|
—
|
|
|||
Refined Products – Futures
|
1
|
|
|
1
|
|
|
—
|
|
|||
Crude:
|
|
|
|
|
|
||||||
Forwards/Swaps
|
2
|
|
|
2
|
|
|
—
|
|
|||
Futures
|
2
|
|
|
2
|
|
|
—
|
|
|||
Total commodity derivatives
|
321
|
|
|
277
|
|
|
44
|
|
|||
Other non-current assets
|
21
|
|
|
14
|
|
|
7
|
|
|||
Total assets
|
$
|
342
|
|
|
$
|
291
|
|
|
$
|
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
|
(28
|
)
|
|
(28
|
)
|
|
—
|
|
|||
Crude:
|
|
|
|
|
|
||||||
Forwards/Swaps
|
(6
|
)
|
|
(6
|
)
|
|
—
|
|
|||
Futures
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Total commodity derivatives
|
(341
|
)
|
|
(303
|
)
|
|
(38
|
)
|
|||
Total liabilities
|
$
|
(560
|
)
|
|
$
|
(303
|
)
|
|
$
|
(257
|
)
|
3.
|
ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
|
•
|
2,263,158
common units representing limited partner interests in Sunoco LP to ETO in exchange for
2,874,275
ETO 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 ETO in exchange for
42,812,389
ETO 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 ETO in exchange for
16,134,903
ETO 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 ETO in exchange for
37,557,815
ETO common units.
|
|
At April 2, 2018
|
||
Total current assets
|
$
|
786
|
|
Property, plant and equipment
|
1,332
|
|
|
Other non-current assets
|
15
|
|
|
Goodwill
(1)
|
366
|
|
|
Intangible assets
|
222
|
|
|
Total assets
|
2,721
|
|
|
|
|
||
Total current liabilities
|
110
|
|
|
Long-term debt, less current maturities
|
1,527
|
|
|
Other non-current liabilities
|
2
|
|
|
Total liabilities
|
1,639
|
|
|
|
|
||
Noncontrolling interest
|
832
|
|
|
|
|
||
Total consideration
|
250
|
|
|
Cash received
(2)
|
711
|
|
|
Total consideration, net of cash received
(2)
|
$
|
(461
|
)
|
(1)
|
None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations.
|
(2)
|
Cash received represents cash and cash equivalents held by USAC as of the acquisition date.
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
Carrying amount of assets classified as held for sale:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
21
|
|
Inventories
|
—
|
|
|
149
|
|
||
Other current assets
|
—
|
|
|
16
|
|
||
Property, plant and equipment, net
|
—
|
|
|
1,851
|
|
||
Goodwill
|
—
|
|
|
796
|
|
||
Intangible assets, net
|
—
|
|
|
477
|
|
||
Other non-current assets, net
|
—
|
|
|
3
|
|
||
Total assets classified as held for sale in the Consolidated Balance Sheet
|
$
|
—
|
|
|
$
|
3,313
|
|
|
|
|
|
||||
Carrying amount of liabilities classified as held for sale:
|
|
|
|
||||
Other current and non-current liabilities
|
$
|
—
|
|
|
$
|
75
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
REVENUES
|
$
|
349
|
|
|
$
|
6,964
|
|
|
$
|
5,712
|
|
|
|
|
|
|
|
||||||
COSTS AND EXPENSES
|
|
|
|
|
|
||||||
Cost of products sold
|
305
|
|
|
5,806
|
|
|
4,649
|
|
|||
Operating expenses
|
61
|
|
|
763
|
|
|
744
|
|
|||
Depreciation, depletion and amortization
|
—
|
|
|
34
|
|
|
143
|
|
|||
Selling, general and administrative
|
7
|
|
|
168
|
|
|
114
|
|
|||
Impairment losses
|
—
|
|
|
285
|
|
|
447
|
|
|||
Total costs and expenses
|
373
|
|
|
7,056
|
|
|
6,097
|
|
|||
OPERATING LOSS
|
(24
|
)
|
|
(92
|
)
|
|
(385
|
)
|
|||
OTHER EXPENSE
|
|
|
|
|
|
||||||
Interest expense, net
|
2
|
|
|
36
|
|
|
28
|
|
|||
Loss on extinguishment of debt
|
20
|
|
|
—
|
|
|
—
|
|
|||
Other, net
|
61
|
|
|
1
|
|
|
8
|
|
|||
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE
|
(107
|
)
|
|
(129
|
)
|
|
(421
|
)
|
|||
Income tax expense
|
158
|
|
|
48
|
|
|
41
|
|
|||
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES
|
$
|
(265
|
)
|
|
$
|
(177
|
)
|
|
$
|
(462
|
)
|
|
At November 1, 2016
|
||
Total current assets
|
$
|
34
|
|
Property, plant and equipment
|
393
|
|
|
Goodwill
(1)
|
177
|
|
|
Intangible assets
|
446
|
|
|
|
1,050
|
|
|
|
|
||
Total current liabilities
|
6
|
|
|
Long-term debt, less current maturities
|
164
|
|
|
Other non-current liabilities
|
17
|
|
|
Noncontrolling interest
|
236
|
|
|
|
423
|
|
|
Total consideration
|
627
|
|
|
Cash received
|
21
|
|
|
Total consideration, net of cash received
|
$
|
606
|
|
(1)
|
None
of the goodwill is expected to be deductible for tax purposes.
|
4.
|
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Citrus
|
$
|
141
|
|
|
$
|
144
|
|
|
$
|
102
|
|
FEP
|
55
|
|
|
53
|
|
|
51
|
|
|||
MEP
|
31
|
|
|
38
|
|
|
40
|
|
|||
HPC
(1)
|
3
|
|
|
(168
|
)
|
|
31
|
|
|||
Other
|
114
|
|
|
77
|
|
|
46
|
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
344
|
|
|
$
|
144
|
|
|
$
|
270
|
|
(1)
|
For the year ended
December 31, 2017
, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by
$185 million
.
|
|
December 31,
|
||||||
|
2018
(1)
|
|
2017
|
||||
Current assets
|
$
|
212
|
|
|
$
|
206
|
|
Property, plant and equipment, net
|
7,800
|
|
|
8,437
|
|
||
Other assets
|
39
|
|
|
43
|
|
||
Total assets
|
$
|
8,051
|
|
|
$
|
8,686
|
|
|
|
|
|
||||
Current liabilities
|
$
|
1,534
|
|
|
$
|
861
|
|
Non-current liabilities
|
3,439
|
|
|
4,492
|
|
||
Equity
|
3,078
|
|
|
3,333
|
|
||
Total liabilities and equity
|
$
|
8,051
|
|
|
$
|
8,686
|
|
(1)
|
Selected balance sheet data as of December 31, 2018 does not include HPC and selected income data related to HPC for the year ended
December 31, 2018
reflects HPC’s results for January 1, 2018 through March 31, 2018. HPC was fully consolidated beginning April 1, 2018 as discussed above.
|
5.
|
DEBT OBLIGATIONS:
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
ETO Debt
|
|
|
|
||||
2.50% Senior Notes due June 15, 2018
|
$
|
—
|
|
|
$
|
650
|
|
6.70% Senior Notes due July 1, 2018
|
—
|
|
|
600
|
|
||
9.70% Senior Notes due March 15, 2019 (1)
|
400
|
|
|
400
|
|
||
9.00% Senior Notes due April 15, 2019 (1)
|
450
|
|
|
450
|
|
||
5.50% Senior Notes due February 15, 2020
|
250
|
|
|
250
|
|
||
5.75% Senior Notes due September 1, 2020
|
400
|
|
|
400
|
|
||
4.15% Senior Notes due October 1, 2020
|
1,050
|
|
|
1,050
|
|
||
4.40% Senior Notes due April 1, 2021
|
600
|
|
|
600
|
|
||
4.65% Senior Notes due June 1, 2021
|
800
|
|
|
800
|
|
||
5.20% Senior Notes due February 1, 2022
|
1,000
|
|
|
1,000
|
|
||
4.65% Senior Notes due February 15, 2022
|
300
|
|
|
300
|
|
||
5.875% Senior Notes due March 1, 2022
|
900
|
|
|
900
|
|
||
5.00% Senior Notes due October 1, 2022
|
700
|
|
|
700
|
|
||
3.45% Senior Notes due January 15, 2023
|
350
|
|
|
350
|
|
||
3.60% Senior Notes due February 1, 2023
|
800
|
|
|
800
|
|
||
4.20% Senior Notes due September 15, 2023
|
500
|
|
|
—
|
|
||
4.50% Senior Notes due November 1, 2023
|
600
|
|
|
600
|
|
||
4.90% Senior Notes due February 1, 2024
|
350
|
|
|
350
|
|
||
7.60% Senior Notes due February 1, 2024
|
277
|
|
|
277
|
|
||
4.25% Senior Notes due April 1, 2024
|
500
|
|
|
500
|
|
||
9.00% Debentures due November 1, 2024
|
65
|
|
|
65
|
|
||
4.05% Senior Notes due March 15, 2025
|
1,000
|
|
|
1,000
|
|
||
5.95% Senior Notes due December 1, 2025
|
400
|
|
|
400
|
|
||
4.75% Senior Notes due January 15, 2026
|
1,000
|
|
|
1,000
|
|
||
3.90% Senior Notes due July 15, 2026
|
550
|
|
|
550
|
|
||
4.20% Senior Notes due April 15, 2027
|
600
|
|
|
600
|
|
||
4.00% Senior Notes due October 1, 2027
|
750
|
|
|
750
|
|
||
4.95% Senior Notes due June 15, 2028
|
1,000
|
|
|
—
|
|
||
8.25% Senior Notes due November 15, 2029
|
267
|
|
|
267
|
|
||
4.90% Senior Notes due March 15, 2035
|
500
|
|
|
500
|
|
||
6.625% Senior Notes due October 15, 2036
|
400
|
|
|
400
|
|
||
5.80% Senior Notes due June 15, 2038
|
500
|
|
|
—
|
|
||
7.50% Senior Notes due July 1, 2038
|
550
|
|
|
550
|
|
||
6.85% Senior Notes due February 15, 2040
|
250
|
|
|
250
|
|
||
6.05% Senior Notes due June 1, 2041
|
700
|
|
|
700
|
|
||
6.50% Senior Notes due February 1, 2042
|
1,000
|
|
|
1,000
|
|
||
6.10% Senior Notes due February 15, 2042
|
300
|
|
|
300
|
|
||
4.95% Senior Notes due January 15, 2043
|
350
|
|
|
350
|
|
5.15% Senior Notes due February 1, 2043
|
450
|
|
|
450
|
|
||
5.95% Senior Notes due October 1, 2043
|
450
|
|
|
450
|
|
||
5.30% Senior Notes due April 1, 2044
|
700
|
|
|
700
|
|
||
5.15% Senior Notes due March 15, 2045
|
1,000
|
|
|
1,000
|
|
||
5.35% Senior Notes due May 15, 2045
|
800
|
|
|
800
|
|
||
6.125% Senior Notes due December 15, 2045
|
1,000
|
|
|
1,000
|
|
||
5.30% Senior Notes due April 15, 2047
|
900
|
|
|
900
|
|
||
5.40% Senior Notes due October 1, 2047
|
1,500
|
|
|
1,500
|
|
||
6.00% Senior Notes due June 15, 2048
|
1,000
|
|
|
—
|
|
||
Floating Rate Junior Subordinated Notes due November 1, 2066
|
546
|
|
|
546
|
|
||
ETO $5.00 billion Revolving Credit Facility due December 2023
|
3,694
|
|
|
2,292
|
|
||
ETO $1.00 billion 364-Day Credit Facility due November 2019
|
—
|
|
|
50
|
|
||
Unamortized premiums, discounts and fair value adjustments, net
|
17
|
|
|
33
|
|
||
Deferred debt issuance costs
|
(178
|
)
|
|
(170
|
)
|
||
|
32,288
|
|
|
29,210
|
|
||
Transwestern Debt
|
|
|
|
||||
5.36% Senior Notes due December 9, 2020
|
175
|
|
|
175
|
|
||
5.89% Senior Notes due May 24, 2022
|
150
|
|
|
150
|
|
||
5.66% Senior Notes due December 9, 2024
|
175
|
|
|
175
|
|
||
6.16% Senior Notes due May 24, 2037
|
75
|
|
|
75
|
|
||
Deferred debt issuance costs
|
(1
|
)
|
|
(1
|
)
|
||
|
574
|
|
|
574
|
|
||
Panhandle Debt
|
|
|
|
||||
7.00% Senior Notes due June 15, 2018
|
—
|
|
|
400
|
|
||
8.125% Senior Notes due June 1, 2019
|
150
|
|
|
150
|
|
||
7.60% Senior Notes due February 1, 2024
|
82
|
|
|
82
|
|
||
7.00% Senior Notes due July 15, 2029
|
66
|
|
|
66
|
|
||
8.25% Senior Notes due November 15, 2029
|
33
|
|
|
33
|
|
||
Floating Rate Junior Subordinated Notes due November 1, 2066
|
54
|
|
|
54
|
|
||
Unamortized premiums, discounts and fair value adjustments, net
|
14
|
|
|
28
|
|
||
|
399
|
|
|
813
|
|
||
Bakken Project Debt
|
|
|
|
||||
Bakken $2.50 billion Credit Facility due August 2019
|
2,500
|
|
|
2,500
|
|
||
Deferred debt issuance costs
|
(3
|
)
|
|
(8
|
)
|
||
|
2,497
|
|
|
2,492
|
|
||
Sunoco LP Debt
|
|
|
|
||||
4.875% Senior Notes Due January 15, 2023
|
1,000
|
|
|
—
|
|
||
5.50% Senior Notes Due February 15, 2026
|
800
|
|
|
—
|
|
||
5.875% Senior Notes Due March 15, 2028
|
400
|
|
|
—
|
|
||
5.50% Senior Notes due August 1, 2020
|
—
|
|
|
600
|
|
||
6.375% Senior Notes due April 1, 2023
|
—
|
|
|
800
|
|
||
6.25% Senior Notes due April 15, 2021
|
—
|
|
|
800
|
|
||
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023
|
700
|
|
|
—
|
|
||
Sunoco LP $1.50 billion Revolving Credit Facility due September 2019
|
—
|
|
|
765
|
|
||
Sunoco LP Term Loan due October 1, 2019
|
—
|
|
|
1,243
|
|
||
Lease-related obligations
|
107
|
|
|
113
|
|
||
Deferred debt issuance costs
|
(23
|
)
|
|
(34
|
)
|
||
|
2,984
|
|
|
4,287
|
|
||
USAC Debt
|
|
|
|
||||
6.875% Senior Notes due April 1, 2026
|
725
|
|
|
—
|
|
||
USAC $1.60 billion Revolving Credit Facility due April 2023
|
1,050
|
|
|
—
|
|
||
Deferred debt issuance costs
|
(16
|
)
|
|
—
|
|
||
|
1,759
|
|
|
—
|
|
||
|
|
|
|
||||
Other
|
7
|
|
|
8
|
|
||
Total debt
|
40,508
|
|
|
37,384
|
|
||
Less: Current maturities of long-term debt
|
2,655
|
|
|
413
|
|
||
Long-term debt, less current maturities
|
$
|
37,853
|
|
|
$
|
36,971
|
|
(1)
|
As of
December 31, 2018
, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The notes were refinanced in January 2019, as discussed below.
|
2019
|
|
$
|
3,505
|
|
2020
|
|
1,881
|
|
|
2021
|
|
1,406
|
|
|
2022
|
|
5,505
|
|
|
2023
|
|
6,255
|
|
|
Thereafter
|
|
22,146
|
|
|
Total
|
|
$
|
40,698
|
|
•
|
redeem in full its existing senior notes, comprised of
$800 million
in aggregate principal amount of
6.250%
senior notes due 2021,
$600 million
in aggregate principal amount of
5.500%
senior notes due 2020 and
$800 million
in aggregate principal amount of
6.375%
senior notes due 2023
;
|
•
|
repay in full and terminate its term loan
;
|
•
|
pay all closing costs in connection with its retail divestment;
|
•
|
redeem the outstanding Sunoco LP Series A Preferred Units
; and
|
•
|
repurchase
17,286,859
Sunoco LP common units owned by ETO
.
|
•
|
incur indebtedness;
|
•
|
grant liens;
|
•
|
enter into mergers;
|
•
|
dispose of assets;
|
•
|
make certain investments;
|
•
|
make Distributions (as defined in the ETO Credit Facilities) during certain Defaults (as defined in the ETO Credit Facilities) and during any Event of Default (as defined in the ETO Credit Facilities);
|
•
|
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
|
•
|
engage in transactions with affiliates; and
|
•
|
enter into restrictive agreements.
|
•
|
prohibition of certain incremental secured indebtedness;
|
•
|
prohibition of certain liens / negative pledge;
|
•
|
limitations on uses of loan proceeds;
|
•
|
limitations on asset sales and purchases;
|
•
|
limitations on permitted business activities;
|
•
|
limitations on mergers and acquisitions;
|
•
|
limitations on investments;
|
•
|
limitations on transactions with affiliates; and
|
•
|
maintenance of commercially reasonable insurance coverage.
|
•
|
grant liens;
|
•
|
make certain loans or investments;
|
•
|
incur additional indebtedness or guarantee other indebtedness;
|
•
|
merge or consolidate;
|
•
|
sell our assets; or
|
•
|
make certain acquisitions.
|
•
|
a minimum EBITDA to interest coverage ratio of
2.5
to
1.0
, determined as of the last day of each fiscal quarter; and
|
•
|
a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending March 31, 2019, (ii) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (iii) 5.0 to 1 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.
|
6.
|
REDEEMABLE NONCONTROLLING INTERESTS
|
7.
|
EQUITY:
|
Period Ended
|
|
Record Date
|
|
Payment Date
|
|
Series A
(1)
|
|
Series B
(1)
|
|
Series C
|
|
Series D
|
|
||||||||
December 31, 2017
|
|
February 1, 2018
|
|
February 15, 2018
|
|
$
|
15.4510
|
|
*
|
$
|
16.3780
|
|
*
|
$
|
—
|
|
|
$
|
—
|
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
31.2500
|
|
|
33.1250
|
|
|
0.5634
|
|
*
|
—
|
|
|
||||
September 30, 2018
|
|
November 1, 2018
|
|
November 15, 2018
|
|
—
|
|
|
—
|
|
|
0.4609
|
|
|
0.5931
|
|
*
|
||||
December 31, 2018
|
|
February 1, 2019
|
|
February 15, 2019
|
|
31.2500
|
|
|
33.1250
|
|
|
0.4609
|
|
|
0.4766
|
|
|
|
|
|
|
Marginal Percentage Interest in Distributions
|
||
|
|
Total Quarterly Distribution Target Amount
|
|
Common Unitholders
|
|
Holder of IDRs
|
Minimum Quarterly Distribution
|
|
$0.4375
|
|
100%
|
|
—%
|
First Target Distribution
|
|
$0.4375 to $0.503125
|
|
100%
|
|
—%
|
Second Target Distribution
|
|
$0.503125 to $0.546875
|
|
85%
|
|
15%
|
Third Target Distribution
|
|
$0.546875 to $0.656250
|
|
75%
|
|
25%
|
Thereafter
|
|
Above $0.656250
|
|
50%
|
|
50%
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2015
|
|
February 5, 2016
|
|
February 16, 2016
|
|
$
|
0.8013
|
|
March 31, 2016
|
|
May 6, 2016
|
|
May 16, 2016
|
|
0.8173
|
|
|
June 30, 2016
|
|
August 5, 2016
|
|
August 15, 2016
|
|
0.8255
|
|
|
September 30, 2016
|
|
November 7, 2016
|
|
November 15, 2016
|
|
0.8255
|
|
|
December 31, 2016
|
|
February 13, 2017
|
|
February 21, 2017
|
|
0.8255
|
|
|
March 31, 2017
|
|
May 9, 2017
|
|
May 16, 2017
|
|
0.8255
|
|
|
June 30, 2017
|
|
August 7, 2017
|
|
August 15, 2017
|
|
0.8255
|
|
|
September 30, 2017
|
|
November 7, 2017
|
|
November 14, 2017
|
|
0.8255
|
|
|
December 31, 2017
|
|
February 6, 2018
|
|
February 14, 2018
|
|
0.8255
|
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 15, 2018
|
|
0.8255
|
|
|
June 30, 2018
|
|
August 7, 2018
|
|
August 15, 2018
|
|
0.8255
|
|
|
September 30, 2018
|
|
November 6, 2018
|
|
November 14, 2018
|
|
0.8255
|
|
|
December 31, 2018
|
|
February 6, 2019
|
|
February 14, 2019
|
|
0.8255
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
March 31, 2018
|
|
May 1, 2018
|
|
May 11, 2018
|
|
$
|
0.5250
|
|
June 30, 2018
|
|
July 30, 2018
|
|
August 10, 2018
|
|
0.5250
|
|
|
September 30, 2018
|
|
October 29, 2018
|
|
November 09, 2018
|
|
0.5250
|
|
|
December 31, 2018
|
|
January 28, 2019
|
|
February 8, 2019
|
|
0.5250
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Available-for-sale securities
(1)
|
$
|
2
|
|
|
$
|
8
|
|
Foreign currency translation adjustment
|
(5
|
)
|
|
(5
|
)
|
||
Actuarial loss related to pensions and other postretirement benefits
|
(48
|
)
|
|
(5
|
)
|
||
Investments in unconsolidated affiliates, net
|
9
|
|
|
5
|
|
||
Total AOCI, net of tax
|
$
|
(42
|
)
|
|
$
|
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 equity securities to common unitholders.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Available-for-sale securities
|
$
|
(1
|
)
|
|
$
|
(2
|
)
|
Foreign currency translation adjustment
|
2
|
|
|
3
|
|
||
Actuarial loss relating to pension and other postretirement benefits
|
12
|
|
|
3
|
|
||
Total
|
$
|
13
|
|
|
$
|
4
|
|
8.
|
NON-CASH COMPENSATION PLANS:
|
|
Sunoco LP
|
|
USAC
|
||||||||||
|
Number of
Units
|
|
Weighted Average
Grant-Date Fair Value
Per Unit
|
|
Number of
Units
|
|
Weighted Average
Grant-Date Fair Value
Per Unit
|
||||||
Unvested awards, beginning of period
(1)
|
1.7
|
|
|
$
|
31.89
|
|
|
1.0
|
|
|
$
|
14.24
|
|
Awards granted
|
1.1
|
|
|
27.67
|
|
|
1.1
|
|
|
15.47
|
|
||
Awards vested
|
(0.4
|
)
|
|
32.92
|
|
|
(0.6
|
)
|
|
14.79
|
|
||
Awards forfeited
|
(0.3
|
)
|
|
31.26
|
|
|
(0.1
|
)
|
|
17.85
|
|
||
Unvested awards as of December 31, 2018
|
2.1
|
|
|
29.15
|
|
|
1.4
|
|
|
14.98
|
|
(1)
|
Amounts reflect Sunoco LP as of January 1, 2018 and USAC as of April 2, 2018 (the date that ET obtained control of USAC).
|
9.
|
INCOME TAXES:
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Current expense (benefit):
|
|
|
|
|
|
||||||
Federal
|
$
|
(7
|
)
|
|
$
|
53
|
|
|
$
|
(47
|
)
|
State
|
20
|
|
|
(16
|
)
|
|
(34
|
)
|
|||
Total
|
13
|
|
|
37
|
|
|
(81
|
)
|
|||
Deferred expense (benefit):
|
|
|
|
|
|
||||||
Federal
|
183
|
|
|
(2,025
|
)
|
|
(185
|
)
|
|||
State
|
(191
|
)
|
|
184
|
|
|
11
|
|
|||
Total
|
(8
|
)
|
|
(1,841
|
)
|
|
(174
|
)
|
|||
Total income tax expense (benefit)
|
$
|
5
|
|
|
$
|
(1,804
|
)
|
|
$
|
(255
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Income tax expense at United States statutory rate
|
$
|
849
|
|
|
$
|
402
|
|
|
$
|
230
|
|
Increase (reduction) in income taxes resulting from:
|
|
|
|
|
|
||||||
Partnership earnings not subject to tax
|
(718
|
)
|
|
(626
|
)
|
|
(728
|
)
|
|||
Federal rate change
|
—
|
|
|
(1,784
|
)
|
|
—
|
|
|||
Goodwill impairments
|
—
|
|
|
208
|
|
|
278
|
|
|||
State income taxes (net of federal income tax effects)
|
(125
|
)
|
|
123
|
|
|
(10
|
)
|
|||
Dividend received deduction
|
(5
|
)
|
|
(14
|
)
|
|
(15
|
)
|
|||
Change in tax status of subsidiary
|
—
|
|
|
(124
|
)
|
|
—
|
|
|||
Other
|
4
|
|
|
11
|
|
|
(10
|
)
|
|||
Income tax expense (benefit)
|
$
|
5
|
|
|
$
|
(1,804
|
)
|
|
$
|
(255
|
)
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Deferred income tax assets:
|
|
|
|
||||
Net operating losses, alternative minimum tax credit and other carryforwards
|
$
|
768
|
|
|
$
|
683
|
|
Pension and other postretirement benefits
|
34
|
|
|
21
|
|
||
Long-term debt
|
13
|
|
|
14
|
|
||
Other
|
181
|
|
|
190
|
|
||
Total deferred income tax assets
|
996
|
|
|
908
|
|
||
Valuation allowance
|
(96
|
)
|
|
(189
|
)
|
||
Net deferred income tax assets
|
$
|
900
|
|
|
$
|
719
|
|
|
|
|
|
||||
Deferred income tax liabilities:
|
|
|
|
||||
Property, plant and equipment
|
$
|
(742
|
)
|
|
$
|
(998
|
)
|
Investment in unconsolidated affiliates
|
(2,869
|
)
|
|
(2,726
|
)
|
||
Trademarks
|
(63
|
)
|
|
(169
|
)
|
||
Other
|
(110
|
)
|
|
(98
|
)
|
||
Total deferred income tax liabilities
|
(3,784
|
)
|
|
(3,991
|
)
|
||
Net deferred income taxes
|
$
|
(2,884
|
)
|
|
$
|
(3,272
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Balance at beginning of year
|
$
|
609
|
|
|
$
|
615
|
|
|
$
|
610
|
|
Additions attributable to tax positions taken in the current year
|
8
|
|
|
—
|
|
|
8
|
|
|||
Additions attributable to tax positions taken in prior years
|
7
|
|
|
28
|
|
|
18
|
|
|||
Reduction attributable to tax positions taken in prior years
|
—
|
|
|
(25
|
)
|
|
(20
|
)
|
|||
Lapse of statute
|
—
|
|
|
(9
|
)
|
|
(1
|
)
|
|||
Balance at end of year
|
$
|
624
|
|
|
$
|
609
|
|
|
$
|
615
|
|
10.
|
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Rental expense
(1)
|
$
|
139
|
|
|
$
|
171
|
|
|
$
|
161
|
|
Sublease rental income
(2)
|
40
|
|
|
25
|
|
|
26
|
|
|||
Net
|
$
|
99
|
|
|
$
|
146
|
|
|
$
|
135
|
|
(1)
|
Includes contingent rentals totaling
$4 million
,
$16 million
and
$18 million
for the years ended
December 31, 2018, 2017 and 2016
, respectively.
|
(2)
|
Sublease rental income is included in other revenues in the accompanying statements of operations.
|
Years Ending December 31:
|
|
||
2019
|
$
|
104
|
|
2020
|
95
|
|
|
2021
|
74
|
|
|
2022
|
58
|
|
|
2023
|
50
|
|
|
Thereafter
|
220
|
|
|
Future minimum lease commitments
|
601
|
|
|
Less: Sublease rental income
|
(111
|
)
|
|
Net future minimum lease commitments
|
$
|
490
|
|
•
|
certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
|
•
|
certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
|
•
|
legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
|
•
|
Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of
December 31, 2018
, Sunoco, Inc. had been named as a PRP at approximately
41
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.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Current
|
$
|
42
|
|
|
$
|
35
|
|
Non-current
|
295
|
|
|
337
|
|
||
Total environmental liabilities
|
$
|
337
|
|
|
$
|
372
|
|
11.
|
REVENUE:
|
•
|
fuel distribution and marketing;
|
•
|
all other;
|
•
|
contract operations;
|
•
|
retail parts and services; and
|
•
|
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.
|
|
Balance at
January 1, 2018
|
|
Balance at December 31, 2018
|
|
Increase (decrease)
|
||||||
Contract Balances
|
|
|
|
|
|
||||||
Contract asset
|
$
|
51
|
|
|
$
|
75
|
|
|
$
|
24
|
|
Accounts receivable from contracts with customers
|
445
|
|
|
347
|
|
|
(98
|
)
|
|||
Contract liability
|
1
|
|
|
1
|
|
|
—
|
|
|
|
Years Ending December 31,
|
|
|
|
|
||||||||||||||
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||
Revenue expected to be recognized on contracts with customers existing as of December 31, 2018
|
|
$
|
5,529
|
|
|
$
|
4,955
|
|
|
$
|
4,413
|
|
|
$
|
27,452
|
|
|
$
|
42,349
|
|
•
|
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
|
•
|
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.
|
•
|
Incremental costs of obtaining a contract:
The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.
|
•
|
Shipping and handling costs:
The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.
|
•
|
Measurement of transaction price:
The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.).
|
•
|
Variable consideration of wholly unsatisfied performance obligations:
The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.
|
12.
|
DERIVATIVE ASSETS AND LIABILITIES:
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||
|
Notional
Volume
|
|
Maturity
|
|
Notional
Volume
|
|
Maturity
|
||
Mark-to-Market Derivatives
|
|
|
|
|
|
|
|
||
(Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
||
Fixed Swaps/Futures
|
468
|
|
|
2019
|
|
1,078
|
|
|
2018
|
Basis Swaps IFERC/NYMEX
(1)
|
16,845
|
|
|
2019-2020
|
|
48,510
|
|
|
2018-2020
|
Options – Puts
|
10,000
|
|
|
2019
|
|
13,000
|
|
|
2018
|
Power (Megawatt):
|
|
|
|
|
|
|
|
||
Forwards
|
3,141,520
|
|
|
2019
|
|
435,960
|
|
|
2018-2019
|
Futures
|
56,656
|
|
|
2019-2021
|
|
(25,760
|
)
|
|
2018
|
Options – Puts
|
18,400
|
|
|
2019
|
|
(153,600
|
)
|
|
2018
|
Options – Calls
|
284,800
|
|
|
2019
|
|
137,600
|
|
|
2018
|
(Non-Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
||
Basis Swaps IFERC/NYMEX
|
(30,228
|
)
|
|
2019-2021
|
|
4,650
|
|
|
2018-2020
|
Swing Swaps IFERC
|
54,158
|
|
|
2019-2020
|
|
87,253
|
|
|
2018-2019
|
Fixed Swaps/Futures
|
(1,068
|
)
|
|
2019-2021
|
|
(4,390
|
)
|
|
2018-2019
|
Forward Physical Contracts
|
(123,254
|
)
|
|
2019-2020
|
|
(145,105
|
)
|
|
2018-2020
|
NGL (MBbls) – Forwards/Swaps
|
(2,135
|
)
|
|
2019
|
|
(2,493
|
)
|
|
2018-2019
|
Crude (MBbls) – Forwards/Swaps
|
20,888
|
|
|
2019
|
|
9,237
|
|
|
2018-2019
|
Refined Products (MBbls) – Futures
|
(1,403
|
)
|
|
2019
|
|
(3,901
|
)
|
|
2018-2019
|
Corn (thousand bushels)
|
(1,920
|
)
|
|
2019
|
|
1,870
|
|
|
2018
|
Fair Value Hedging Derivatives
|
|
|
|
|
|
|
|
||
(Non-Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
||
Basis Swaps IFERC/NYMEX
|
(17,445
|
)
|
|
2019
|
|
(39,770
|
)
|
|
2018
|
Fixed Swaps/Futures
|
(17,445
|
)
|
|
2019
|
|
(39,770
|
)
|
|
2018
|
Hedged Item – Inventory
|
17,445
|
|
|
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.
|
Term
|
|
Type
(1)
|
|
Notional Amount Outstanding
|
||||||
December 31, 2018
|
|
December 31, 2017
|
||||||||
July 2018
(2)
|
|
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 3.56% 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
|
|
|
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 and receive a fixed rate of 1.53%
|
|
—
|
|
|
1,200
|
|
||
March 2019
|
|
Pay a floating rate 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.
|
|
Fair Value of Derivative Instruments
|
||||||||||||||
|
Asset Derivatives
|
|
Liability Derivatives
|
||||||||||||
|
December 31, 2018
|
|
December 31, 2017
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives (margin deposits)
|
$
|
—
|
|
|
$
|
14
|
|
|
$
|
(13
|
)
|
|
$
|
(2
|
)
|
|
—
|
|
|
14
|
|
|
(13
|
)
|
|
(2
|
)
|
||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives (margin deposits)
|
402
|
|
|
262
|
|
|
(397
|
)
|
|
(281
|
)
|
||||
Commodity derivatives
|
158
|
|
|
45
|
|
|
(173
|
)
|
|
(58
|
)
|
||||
Interest rate derivatives
|
—
|
|
|
—
|
|
|
(163
|
)
|
|
(219
|
)
|
||||
|
560
|
|
|
307
|
|
|
(733
|
)
|
|
(558
|
)
|
||||
Total derivatives
|
$
|
560
|
|
|
$
|
321
|
|
|
$
|
(746
|
)
|
|
$
|
(560
|
)
|
|
Location of Gain (Loss) Recognized in Income on Derivatives
|
|
Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
|
||||||||||
|
|
|
Years Ended December 31,
|
||||||||||
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Derivatives in fair value hedging relationships (including hedged item):
|
|
|
|
|
|
|
|
||||||
Commodity derivatives
|
Cost of products sold
|
|
$
|
(3
|
)
|
|
$
|
26
|
|
|
$
|
14
|
|
|
Location of Gain (Loss) Recognized in Income on Derivatives
|
|
Amount of Gain (Loss) Recognized in Income on Derivatives
|
||||||||||
|
|
|
Years Ended December 31,
|
||||||||||
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||
Commodity derivatives – Trading
|
Cost of products sold
|
|
$
|
32
|
|
|
$
|
31
|
|
|
$
|
(35
|
)
|
Commodity derivatives – Non-trading
|
Cost of products sold
|
|
(102
|
)
|
|
5
|
|
|
(177
|
)
|
|||
Interest rate derivatives
|
Gains (losses) on interest rate derivatives
|
|
47
|
|
|
(37
|
)
|
|
(12
|
)
|
|||
Embedded derivatives
|
Other, net
|
|
—
|
|
|
1
|
|
|
4
|
|
|||
Total
|
|
|
$
|
(23
|
)
|
|
$
|
—
|
|
|
$
|
(220
|
)
|
13.
|
RETIREMENT BENEFITS:
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||
|
Pension Benefits
|
|
|
|
Pension Benefits
|
|
|
||||||||||||||||
|
Funded Plans
|
|
Unfunded Plans
|
|
Other Postretirement Benefits
|
|
Funded Plans
|
|
Unfunded Plans
|
|
Other Postretirement Benefits
|
||||||||||||
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Benefit obligation at beginning of period
|
$
|
1
|
|
|
$
|
47
|
|
|
$
|
156
|
|
|
$
|
18
|
|
|
$
|
51
|
|
|
$
|
166
|
|
Service cost
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Interest cost
|
—
|
|
|
1
|
|
|
5
|
|
|
1
|
|
|
1
|
|
|
4
|
|
||||||
Amendments
|
—
|
|
|
—
|
|
|
60
|
|
|
—
|
|
|
—
|
|
|
7
|
|
||||||
Benefits paid, net
|
—
|
|
|
(7
|
)
|
|
(17
|
)
|
|
(2
|
)
|
|
(6
|
)
|
|
(20
|
)
|
||||||
Actuarial (gain) loss and other
|
—
|
|
|
(4
|
)
|
|
(7
|
)
|
|
2
|
|
|
1
|
|
|
(1
|
)
|
||||||
Settlements
|
—
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
—
|
|
||||||
Benefit obligation at end of period
|
1
|
|
|
37
|
|
|
198
|
|
|
1
|
|
|
47
|
|
|
156
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Change in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fair value of plan assets at beginning of period
|
1
|
|
|
—
|
|
|
257
|
|
|
12
|
|
|
—
|
|
|
256
|
|
||||||
Return on plan assets and other
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
3
|
|
|
—
|
|
|
11
|
|
||||||
Employer contributions
|
—
|
|
|
—
|
|
|
9
|
|
|
6
|
|
|
—
|
|
|
10
|
|
||||||
Benefits paid, net
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
(2
|
)
|
|
—
|
|
|
(20
|
)
|
||||||
Settlements
|
—
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
—
|
|
||||||
Fair value of plan assets at end of period
|
1
|
|
|
—
|
|
|
241
|
|
|
1
|
|
|
—
|
|
|
257
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amount underfunded (overfunded) at end of period
|
$
|
—
|
|
|
$
|
37
|
|
|
$
|
(43
|
)
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
(101
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amounts recognized in the consolidated balance sheets consist of:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Non-current assets
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
127
|
|
Current liabilities
|
—
|
|
|
(6
|
)
|
|
(2
|
)
|
|
—
|
|
|
(8
|
)
|
|
(2
|
)
|
||||||
Non-current liabilities
|
—
|
|
|
(31
|
)
|
|
(23
|
)
|
|
—
|
|
|
(39
|
)
|
|
(24
|
)
|
||||||
|
$
|
—
|
|
|
$
|
(37
|
)
|
|
$
|
43
|
|
|
$
|
—
|
|
|
$
|
(47
|
)
|
|
$
|
101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial gain (loss)
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
(7
|
)
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
(18
|
)
|
Prior service cost
|
—
|
|
|
—
|
|
|
66
|
|
|
—
|
|
|
—
|
|
|
21
|
|
||||||
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
59
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
3
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||
|
Pension Benefits
|
|
|
|
Pension Benefits
|
|
|
||||||||||||||||
|
Funded Plans
|
|
Unfunded Plans
|
|
Other Postretirement Benefits
|
|
Funded Plans
|
|
Unfunded Plans
|
|
Other Postretirement Benefits
|
||||||||||||
Projected benefit obligation
|
$
|
—
|
|
|
$
|
37
|
|
|
N/A
|
|
|
$
|
1
|
|
|
$
|
47
|
|
|
N/A
|
|
||
Accumulated benefit obligation
|
1
|
|
|
37
|
|
|
$
|
198
|
|
|
1
|
|
|
47
|
|
|
$
|
156
|
|
||||
Fair value of plan assets
|
1
|
|
|
—
|
|
|
241
|
|
|
1
|
|
|
—
|
|
|
257
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||
Net periodic benefit cost:
|
|
|
|
|
|
|
|
||||||||
Service cost
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest cost
|
1
|
|
|
5
|
|
|
2
|
|
|
4
|
|
||||
Expected return on plan assets
|
—
|
|
|
(10
|
)
|
|
—
|
|
|
(9
|
)
|
||||
Prior service cost amortization
|
—
|
|
|
16
|
|
|
—
|
|
|
2
|
|
||||
Net periodic benefit cost
|
$
|
1
|
|
|
$
|
12
|
|
|
$
|
2
|
|
|
$
|
(3
|
)
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||
Discount rate
|
4.02
|
%
|
|
3.40
|
%
|
|
3.27
|
%
|
|
2.34
|
%
|
Rate of compensation increase
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||
Discount rate
|
3.52
|
%
|
|
3.51
|
%
|
|
3.52
|
%
|
|
3.10
|
%
|
Expected return on assets:
|
|
|
|
|
|
|
|
||||
Tax exempt accounts
|
3.26
|
%
|
|
6.63
|
%
|
|
3.50
|
%
|
|
7.00
|
%
|
Taxable accounts
|
N/A
|
|
|
4.50
|
%
|
|
N/A
|
|
|
4.50
|
%
|
Rate of compensation increase
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
December 31,
|
||||
|
2018
|
|
2017
|
||
Health care cost trend rate
|
7.15
|
%
|
|
7.20
|
%
|
Rate to which the cost trend is assumed to decline (the ultimate trend rate)
|
4.82
|
%
|
|
4.99
|
%
|
Year that the rate reaches the ultimate trend rate
|
2024
|
|
|
2023
|
|
|
|
|
Fair Value Measurements at December 31, 2018
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Mutual funds
(1)
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Comprised of approximately
100%
equities as of
December 31, 2018
.
|
|
|
|
Fair Value Measurements at December 31, 2017
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Mutual funds
(1)
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Comprised of approximately
100%
equities as of
December 31, 2017
.
|
|
|
|
Fair Value Measurements at December 31, 2018
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Asset category:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
20
|
|
|
$
|
20
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mutual funds
(1)
|
144
|
|
|
144
|
|
|
—
|
|
|
—
|
|
||||
Fixed income securities
|
77
|
|
|
—
|
|
|
77
|
|
|
—
|
|
||||
Total
|
$
|
241
|
|
|
$
|
164
|
|
|
$
|
77
|
|
|
$
|
—
|
|
(1)
|
Primarily comprised of approximately
53%
equities,
46%
fixed income securities and
1%
cash as of
December 31, 2018
.
|
|
|
|
Fair Value Measurements at December 31, 2017
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Asset category:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
33
|
|
|
$
|
33
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mutual funds
(1)
|
154
|
|
|
154
|
|
|
—
|
|
|
—
|
|
||||
Fixed income securities
|
70
|
|
|
—
|
|
|
70
|
|
|
—
|
|
||||
Total
|
$
|
257
|
|
|
$
|
187
|
|
|
$
|
70
|
|
|
$
|
—
|
|
(1)
|
Primarily comprised of approximately
38%
equities,
61%
fixed income securities and
2%
cash as of
December 31, 2017
.
|
Years
|
|
Pension Benefits - Unfunded Plans
(1)
|
|
Other Postretirement Benefits (Gross, Before Medicare Part D)
|
||||
2019
|
|
$
|
6
|
|
|
$
|
20
|
|
2020
|
|
6
|
|
|
20
|
|
||
2021
|
|
5
|
|
|
20
|
|
||
2022
|
|
4
|
|
|
18
|
|
||
2023
|
|
4
|
|
|
17
|
|
||
2024 - 2028
|
|
12
|
|
|
66
|
|
14.
|
RELATED PARTY TRANSACTIONS:
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Affiliated revenues
|
$
|
431
|
|
|
$
|
303
|
|
|
$
|
221
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Accounts receivable from related companies:
|
|
|
|
||||
ET
|
$
|
65
|
|
|
$
|
—
|
|
FGT
|
25
|
|
|
11
|
|
||
Phillips 66
|
42
|
|
|
20
|
|
||
Other
|
44
|
|
|
22
|
|
||
Total accounts receivable from related companies
|
$
|
176
|
|
|
$
|
53
|
|
|
|
|
|
||||
Accounts payable to related companies:
|
|
|
|
||||
ET
|
$
|
59
|
|
|
$
|
64
|
|
Other
|
60
|
|
|
31
|
|
||
Total accounts payable to related companies
|
$
|
119
|
|
|
$
|
95
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Long-term notes receivable – related companies:
|
|
|
|
||||
ET
|
$
|
440
|
|
|
$
|
617
|
|
15.
|
REPORTABLE SEGMENTS:
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Intrastate transportation and storage:
|
|
|
|
|
|
||||||
Revenues from external customers
|
$
|
3,428
|
|
|
$
|
2,891
|
|
|
$
|
2,155
|
|
Intersegment revenues
|
309
|
|
|
192
|
|
|
458
|
|
|||
|
3,737
|
|
|
3,083
|
|
|
2,613
|
|
|||
Interstate transportation and storage:
|
|
|
|
|
|
||||||
Revenues from external customers
|
1,664
|
|
|
1,112
|
|
|
1,143
|
|
|||
Intersegment revenues
|
18
|
|
|
19
|
|
|
23
|
|
|||
|
1,682
|
|
|
1,131
|
|
|
1,166
|
|
|||
Midstream:
|
|
|
|
|
|
||||||
Revenues from external customers
|
2,090
|
|
|
2,510
|
|
|
2,342
|
|
|||
Intersegment revenues
|
5,432
|
|
|
4,433
|
|
|
2,837
|
|
|||
|
7,522
|
|
|
6,943
|
|
|
5,179
|
|
|||
NGL and refined products transportation and services:
|
|
|
|
|
|
||||||
Revenues from external customers
|
10,119
|
|
|
7,885
|
|
|
5,764
|
|
|||
Intersegment revenues
|
1,004
|
|
|
763
|
|
|
645
|
|
|||
|
11,123
|
|
|
8,648
|
|
|
6,409
|
|
|||
Crude oil transportation and services:
|
|
|
|
|
|
||||||
Revenues from external customers
|
17,236
|
|
|
11,672
|
|
|
7,539
|
|
|||
Intersegment revenues
|
96
|
|
|
31
|
|
|
—
|
|
|||
|
17,332
|
|
|
11,703
|
|
|
7,539
|
|
|||
Investment in Sunoco LP:
|
|
|
|
|
|
||||||
Revenues from external customers
|
16,982
|
|
|
11,713
|
|
|
9,977
|
|
|||
Intersegment revenues
|
12
|
|
|
10
|
|
|
9
|
|
|||
|
16,994
|
|
|
11,723
|
|
|
9,986
|
|
|||
Investment in USAC:
|
|
|
|
|
|
||||||
Revenues from external customers
|
495
|
|
|
—
|
|
|
—
|
|
|||
Intersegment revenues
|
13
|
|
|
—
|
|
|
—
|
|
|||
|
508
|
|
|
—
|
|
|
—
|
|
|||
All other:
|
|
|
|
|
|
||||||
Revenues from external customers
|
2,073
|
|
|
2,740
|
|
|
2,872
|
|
|||
Intersegment revenues
|
155
|
|
|
161
|
|
|
400
|
|
|||
|
2,228
|
|
|
2,901
|
|
|
3,272
|
|
|||
Eliminations
|
(7,039
|
)
|
|
(5,609
|
)
|
|
(4,372
|
)
|
|||
Total revenues
|
$
|
54,087
|
|
|
$
|
40,523
|
|
|
$
|
31,792
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cost of products sold:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
2,665
|
|
|
$
|
2,327
|
|
|
$
|
1,897
|
|
Midstream
|
5,145
|
|
|
4,761
|
|
|
3,381
|
|
|||
NGL and refined products transportation and services
|
8,462
|
|
|
6,508
|
|
|
4,553
|
|
|||
Crude oil transportation and services
|
14,439
|
|
|
9,826
|
|
|
6,416
|
|
|||
Investment in Sunoco LP
|
15,872
|
|
|
10,615
|
|
|
8,830
|
|
|||
Investment in USAC
|
67
|
|
|
—
|
|
|
—
|
|
|||
All other
|
2,006
|
|
|
2,509
|
|
|
2,942
|
|
|||
Eliminations
|
(6,998
|
)
|
|
(5,580
|
)
|
|
(4,326
|
)
|
|||
Total cost of products sold
|
$
|
41,658
|
|
|
$
|
30,966
|
|
|
$
|
23,693
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Depreciation, depletion and amortization:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
169
|
|
|
$
|
147
|
|
|
$
|
144
|
|
Interstate transportation and storage
|
334
|
|
|
254
|
|
|
246
|
|
|||
Midstream
|
1,006
|
|
|
954
|
|
|
840
|
|
|||
NGL and refined products transportation and services
|
466
|
|
|
401
|
|
|
355
|
|
|||
Crude oil transportation and services
|
445
|
|
|
402
|
|
|
251
|
|
|||
Investment in Sunoco LP
|
167
|
|
|
169
|
|
|
176
|
|
|||
Investment in USAC
|
169
|
|
|
—
|
|
|
—
|
|
|||
All other
|
87
|
|
|
214
|
|
|
189
|
|
|||
Total depreciation, depletion and amortization
|
$
|
2,843
|
|
|
$
|
2,541
|
|
|
$
|
2,201
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Equity in earnings (losses) of unconsolidated affiliates:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
19
|
|
|
$
|
(156
|
)
|
|
$
|
35
|
|
Interstate transportation and storage
|
227
|
|
|
236
|
|
|
193
|
|
|||
Midstream
|
26
|
|
|
20
|
|
|
19
|
|
|||
NGL and refined products transportation and services
|
64
|
|
|
33
|
|
|
41
|
|
|||
Crude oil transportation and services
|
6
|
|
|
4
|
|
|
(4
|
)
|
|||
All other
|
2
|
|
|
7
|
|
|
(14
|
)
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
344
|
|
|
$
|
144
|
|
|
$
|
270
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
927
|
|
|
$
|
626
|
|
|
$
|
613
|
|
Interstate transportation and storage
|
1,680
|
|
|
1,274
|
|
|
1,297
|
|
|||
Midstream
|
1,627
|
|
|
1,481
|
|
|
1,133
|
|
|||
NGL and refined products transportation and services
|
1,979
|
|
|
1,641
|
|
|
1,496
|
|
|||
Crude oil transportation and services
|
2,330
|
|
|
1,379
|
|
|
834
|
|
|||
Investment in Sunoco LP
|
638
|
|
|
732
|
|
|
665
|
|
|||
Investment in USAC
|
289
|
|
|
—
|
|
|
—
|
|
|||
All other
|
76
|
|
|
219
|
|
|
193
|
|
|||
Total Segment Adjusted EBITDA
|
9,546
|
|
|
7,352
|
|
|
6,231
|
|
|||
Depreciation, depletion and amortization
|
(2,843
|
)
|
|
(2,541
|
)
|
|
(2,201
|
)
|
|||
Interest expense, net
|
(1,709
|
)
|
|
(1,575
|
)
|
|
(1,478
|
)
|
|||
Gains on acquisitions
|
—
|
|
|
—
|
|
|
83
|
|
|||
Impairment losses
|
(431
|
)
|
|
(1,039
|
)
|
|
(1,040
|
)
|
|||
Gains (losses) on interest rate derivatives
|
47
|
|
|
(37
|
)
|
|
(12
|
)
|
|||
Non-cash compensation expense
|
(105
|
)
|
|
(99
|
)
|
|
(93
|
)
|
|||
Unrealized gains (losses) on commodity risk management activities
|
(11
|
)
|
|
59
|
|
|
(136
|
)
|
|||
Inventory valuation adjustments
|
(85
|
)
|
|
24
|
|
|
97
|
|
|||
Losses on extinguishments of debt
|
(109
|
)
|
|
(42
|
)
|
|
—
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
(655
|
)
|
|
(716
|
)
|
|
(675
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
344
|
|
|
144
|
|
|
270
|
|
|||
Impairment of investments in unconsolidated affiliates
|
—
|
|
|
(313
|
)
|
|
(308
|
)
|
|||
Adjusted EBITDA related to discontinued operations
|
25
|
|
|
(223
|
)
|
|
(199
|
)
|
|||
Other, net
|
30
|
|
|
154
|
|
|
117
|
|
|||
Income from continuing operations before income tax (expense) benefit
|
4,044
|
|
|
1,148
|
|
|
656
|
|
|||
Income tax (expense) benefit from continuing operations
|
(5
|
)
|
|
1,804
|
|
|
255
|
|
|||
Income from continuing operations
|
4,039
|
|
|
2,952
|
|
|
911
|
|
|||
Loss from discontinued operations, net of income taxes
|
(265
|
)
|
|
(177
|
)
|
|
(462
|
)
|
|||
Net income
|
$
|
3,774
|
|
|
$
|
2,775
|
|
|
$
|
449
|
|
|
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Assets:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
6,365
|
|
|
$
|
5,020
|
|
|
$
|
5,174
|
|
Interstate transportation and storage
|
15,081
|
|
|
15,316
|
|
|
12,492
|
|
|||
Midstream
|
19,745
|
|
|
20,004
|
|
|
17,873
|
|
|||
NGL and refined products transportation and services
|
18,267
|
|
|
17,600
|
|
|
14,074
|
|
|||
Crude oil transportation and services
|
18,022
|
|
|
17,730
|
|
|
15,908
|
|
|||
Investment in Sunoco LP
|
4,879
|
|
|
8,344
|
|
|
8,701
|
|
|||
Investment in USAC
|
3,775
|
|
|
—
|
|
|
—
|
|
|||
All other and eliminations
|
2,308
|
|
|
2,470
|
|
|
4,762
|
|
|||
Total assets
|
$
|
88,442
|
|
|
$
|
86,484
|
|
|
$
|
78,984
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
344
|
|
|
$
|
175
|
|
|
$
|
76
|
|
Interstate transportation and storage
|
812
|
|
|
728
|
|
|
280
|
|
|||
Midstream
|
1,161
|
|
|
1,308
|
|
|
1,255
|
|
|||
NGL and refined products transportation and services
|
2,381
|
|
|
2,971
|
|
|
2,198
|
|
|||
Crude oil transportation and services
|
474
|
|
|
453
|
|
|
1,841
|
|
|||
Investment in Sunoco LP
|
103
|
|
|
103
|
|
|
119
|
|
|||
Investment in USAC
|
205
|
|
|
—
|
|
|
—
|
|
|||
All other
|
150
|
|
|
268
|
|
|
160
|
|
|||
Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis)
|
$
|
5,630
|
|
|
$
|
6,006
|
|
|
$
|
5,929
|
|
|
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Advances to and investments in unconsolidated affiliates:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
83
|
|
|
$
|
85
|
|
|
$
|
387
|
|
Interstate transportation and storage
|
2,070
|
|
|
2,118
|
|
|
2,149
|
|
|||
Midstream
|
124
|
|
|
126
|
|
|
111
|
|
|||
NGL and refined products transportation and services
|
243
|
|
|
234
|
|
|
235
|
|
|||
Crude oil transportation and services
|
28
|
|
|
22
|
|
|
18
|
|
|||
All other
|
88
|
|
|
113
|
|
|
131
|
|
|||
Total advances to and investments in unconsolidated affiliates
|
$
|
2,636
|
|
|
$
|
2,698
|
|
|
$
|
3,031
|
|
16.
|
QUARTERLY FINANCIAL DATA (UNAUDITED):
|
|
Quarters Ended
|
|
|
||||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Total Year
|
||||||||||
2018:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
11,882
|
|
|
$
|
14,118
|
|
|
$
|
14,514
|
|
|
$
|
13,573
|
|
|
$
|
54,087
|
|
Operating income
|
1,105
|
|
|
1,138
|
|
|
1,715
|
|
|
1,444
|
|
|
5,402
|
|
|||||
Income from continuing operations
|
814
|
|
|
760
|
|
|
1,494
|
|
|
971
|
|
|
4,039
|
|
|||||
Net income
|
577
|
|
|
734
|
|
|
1,492
|
|
|
971
|
|
|
3,774
|
|
|||||
Net income attributable to partners
|
715
|
|
|
432
|
|
|
1,135
|
|
|
743
|
|
|
3,025
|
|
|
Quarters Ended
|
|
|
||||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Total Year
|
||||||||||
2017:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
9,660
|
|
|
$
|
9,427
|
|
|
$
|
9,984
|
|
|
$
|
11,452
|
|
|
$
|
40,523
|
|
Operating income
|
775
|
|
|
754
|
|
|
938
|
|
|
298
|
|
|
2,765
|
|
|||||
Income from continuing operations
|
456
|
|
|
410
|
|
|
835
|
|
|
1,251
|
|
|
2,952
|
|
|||||
Net income
|
445
|
|
|
217
|
|
|
852
|
|
|
1,261
|
|
|
2,775
|
|
|||||
Net income attributable to partners
|
331
|
|
|
202
|
|
|
605
|
|
|
943
|
|
|
2,081
|
|
17.
|
CONSOLIDATING GUARANTOR FINANCIAL INFORMATION
|
|
December 31, 2018
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
418
|
|
|
$
|
—
|
|
|
$
|
418
|
|
All other current assets
|
5
|
|
|
57
|
|
|
7,074
|
|
|
(734
|
)
|
|
6,402
|
|
|||||
Property, plant and equipment
|
—
|
|
|
—
|
|
|
66,655
|
|
|
—
|
|
|
66,655
|
|
|||||
Investments in unconsolidated affiliates
|
51,876
|
|
|
13,090
|
|
|
2,636
|
|
|
(64,966
|
)
|
|
2,636
|
|
|||||
All other assets
|
12
|
|
|
75
|
|
|
12,244
|
|
|
—
|
|
|
12,331
|
|
|||||
Total assets
|
$
|
51,893
|
|
|
$
|
13,222
|
|
|
$
|
89,027
|
|
|
$
|
(65,700
|
)
|
|
$
|
88,442
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
$
|
(635
|
)
|
|
$
|
(3,315
|
)
|
|
$
|
14,469
|
|
|
$
|
(1,222
|
)
|
|
$
|
9,297
|
|
Non-current liabilities
|
24,787
|
|
|
7,605
|
|
|
10,132
|
|
|
—
|
|
|
42,524
|
|
|||||
Noncontrolling interest
|
—
|
|
|
—
|
|
|
7,903
|
|
|
—
|
|
|
7,903
|
|
|||||
Total partners’ capital
|
27,741
|
|
|
8,932
|
|
|
56,523
|
|
|
(64,478
|
)
|
|
28,718
|
|
|||||
Total liabilities and equity
|
$
|
51,893
|
|
|
$
|
13,222
|
|
|
$
|
89,027
|
|
|
$
|
(65,700
|
)
|
|
$
|
88,442
|
|
|
December 31, 2017
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
337
|
|
|
$
|
—
|
|
|
$
|
335
|
|
All other current assets
|
—
|
|
|
159
|
|
|
10,187
|
|
|
—
|
|
|
10,346
|
|
|||||
Property, plant and equipment
|
—
|
|
|
—
|
|
|
60,764
|
|
|
—
|
|
|
60,764
|
|
|||||
Investments in unconsolidated affiliates
|
51,194
|
|
|
11,648
|
|
|
2,698
|
|
|
(62,842
|
)
|
|
2,698
|
|
|||||
All other assets
|
—
|
|
|
—
|
|
|
12,341
|
|
|
—
|
|
|
12,341
|
|
|||||
Total assets
|
$
|
51,194
|
|
|
$
|
11,805
|
|
|
$
|
86,327
|
|
|
$
|
(62,842
|
)
|
|
$
|
86,484
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
$
|
(1,496
|
)
|
|
$
|
(3,660
|
)
|
|
$
|
13,047
|
|
|
$
|
—
|
|
|
$
|
7,891
|
|
Non-current liabilities
|
21,604
|
|
|
7,608
|
|
|
12,414
|
|
|
—
|
|
|
41,626
|
|
|||||
Noncontrolling interest
|
—
|
|
|
—
|
|
|
5,882
|
|
|
—
|
|
|
5,882
|
|
|||||
Total partners’ capital
|
31,086
|
|
|
7,857
|
|
|
54,984
|
|
|
(62,842
|
)
|
|
31,085
|
|
|||||
Total liabilities and equity
|
$
|
51,194
|
|
|
$
|
11,805
|
|
|
$
|
86,327
|
|
|
$
|
(62,842
|
)
|
|
$
|
86,484
|
|
|
Year Ended December 31, 2018
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
54,087
|
|
|
$
|
—
|
|
|
$
|
54,087
|
|
Operating costs, expenses, and other
|
—
|
|
|
—
|
|
|
48,685
|
|
|
—
|
|
|
48,685
|
|
|||||
Operating income
|
—
|
|
|
—
|
|
|
5,402
|
|
|
—
|
|
|
5,402
|
|
|||||
Interest expense, net
|
(1,196
|
)
|
|
(176
|
)
|
|
(337
|
)
|
|
—
|
|
|
(1,709
|
)
|
|||||
Equity in earnings of unconsolidated affiliates
|
4,170
|
|
|
1,430
|
|
|
344
|
|
|
(5,600
|
)
|
|
344
|
|
|||||
Losses on debt extinguishment
|
—
|
|
|
—
|
|
|
(109
|
)
|
|
—
|
|
|
(109
|
)
|
|||||
Gains on interest rate derivatives
|
47
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47
|
|
|||||
Other, net
|
—
|
|
|
—
|
|
|
69
|
|
|
—
|
|
|
69
|
|
|||||
Income before income tax expense
|
3,021
|
|
|
1,254
|
|
|
5,369
|
|
|
(5,600
|
)
|
|
4,044
|
|
|||||
Income tax expense
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
|||||
Net income from continuing operations
|
3,021
|
|
|
1,254
|
|
|
5,364
|
|
|
(5,600
|
)
|
|
4,039
|
|
|||||
Net loss attributable to discontinued operations
|
—
|
|
|
—
|
|
|
(265
|
)
|
|
—
|
|
|
(265
|
)
|
|||||
Net income
|
3,021
|
|
|
1,254
|
|
|
5,099
|
|
|
(5,600
|
)
|
|
3,774
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
715
|
|
|
—
|
|
|
715
|
|
|||||
Less: Net income attributable to redeemable noncontrolling interests
|
—
|
|
|
—
|
|
|
39
|
|
|
—
|
|
|
39
|
|
|||||
Less: Net loss attributable to predecessor
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
|||||
Net income attributable to partners
|
$
|
3,021
|
|
|
$
|
1,254
|
|
|
$
|
4,350
|
|
|
$
|
(5,600
|
)
|
|
$
|
3,025
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other comprehensive loss
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(43
|
)
|
|
$
|
—
|
|
|
$
|
(43
|
)
|
Comprehensive income
|
3,021
|
|
|
1,254
|
|
|
5,056
|
|
|
(5,600
|
)
|
|
3,731
|
|
|||||
Comprehensive income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
715
|
|
|
—
|
|
|
715
|
|
|||||
Comprehensive income attributable to redeemable noncontrolling interests
|
—
|
|
|
—
|
|
|
39
|
|
|
—
|
|
|
39
|
|
|||||
Comprehensive income attributable to predecessor
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
|||||
Comprehensive income attributable to partners
|
$
|
3,021
|
|
|
$
|
1,254
|
|
|
$
|
4,307
|
|
|
$
|
(5,600
|
)
|
|
$
|
2,982
|
|
|
Year Ended December 31, 2017
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
40,523
|
|
|
$
|
—
|
|
|
$
|
40,523
|
|
Operating costs, expenses, and other
|
—
|
|
|
1
|
|
|
37,757
|
|
|
—
|
|
|
37,758
|
|
|||||
Operating income (loss)
|
—
|
|
|
(1
|
)
|
|
2,766
|
|
|
—
|
|
|
2,765
|
|
|||||
Interest expense, net
|
—
|
|
|
(156
|
)
|
|
(1,419
|
)
|
|
—
|
|
|
(1,575
|
)
|
|||||
Equity in earnings of unconsolidated affiliates
|
2,564
|
|
|
1,242
|
|
|
144
|
|
|
(3,806
|
)
|
|
144
|
|
|||||
Impairment of investment in unconsolidated affiliate
|
—
|
|
|
—
|
|
|
(313
|
)
|
|
—
|
|
|
(313
|
)
|
|||||
Losses on extinguishments of debt
|
—
|
|
|
—
|
|
|
(42
|
)
|
|
—
|
|
|
(42
|
)
|
|||||
Losses on interest rate derivatives
|
—
|
|
|
—
|
|
|
(37
|
)
|
|
—
|
|
|
(37
|
)
|
|||||
Other, net
|
—
|
|
|
—
|
|
|
207
|
|
|
(1
|
)
|
|
206
|
|
|||||
Income before income tax benefit
|
2,564
|
|
|
1,085
|
|
|
1,306
|
|
|
(3,807
|
)
|
|
1,148
|
|
|||||
Income tax benefit
|
—
|
|
|
—
|
|
|
(1,804
|
)
|
|
—
|
|
|
(1,804
|
)
|
|||||
Net income from continuing operations
|
2,564
|
|
|
1,085
|
|
|
3,110
|
|
|
(3,807
|
)
|
|
2,952
|
|
|||||
Net loss attributable to discontinued operations
|
—
|
|
|
—
|
|
|
(177
|
)
|
|
—
|
|
|
(177
|
)
|
|||||
Net income
|
2,564
|
|
|
1,085
|
|
|
2,933
|
|
|
(3,807
|
)
|
|
2,775
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
420
|
|
|
—
|
|
|
420
|
|
|||||
Less: Net income attributable to predecessor
|
—
|
|
|
—
|
|
|
274
|
|
|
—
|
|
|
274
|
|
|||||
Net income attributable to partners
|
$
|
2,564
|
|
|
$
|
1,085
|
|
|
$
|
2,239
|
|
|
$
|
(3,807
|
)
|
|
$
|
2,081
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other comprehensive loss
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(5
|
)
|
|
$
|
—
|
|
|
$
|
(5
|
)
|
Comprehensive income
|
2,564
|
|
|
1,085
|
|
|
2,928
|
|
|
(3,807
|
)
|
|
2,770
|
|
|||||
Comprehensive income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
420
|
|
|
—
|
|
|
420
|
|
|||||
Comprehensive income attributable to predecessor
|
—
|
|
|
—
|
|
|
274
|
|
|
—
|
|
|
274
|
|
|||||
Comprehensive income attributable to partners
|
$
|
2,564
|
|
|
$
|
1,085
|
|
|
$
|
2,234
|
|
|
$
|
(3,807
|
)
|
|
$
|
2,076
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
31,792
|
|
|
$
|
—
|
|
|
$
|
31,792
|
|
Operating costs, expenses, and other
|
—
|
|
|
1
|
|
|
29,816
|
|
|
—
|
|
|
29,817
|
|
|||||
Operating income (loss)
|
—
|
|
|
(1
|
)
|
|
1,976
|
|
|
—
|
|
|
1,975
|
|
|||||
Interest expense, net
|
—
|
|
|
(157
|
)
|
|
(1,321
|
)
|
|
—
|
|
|
(1,478
|
)
|
|||||
Equity in earnings of unconsolidated affiliates
|
554
|
|
|
863
|
|
|
270
|
|
|
(1,417
|
)
|
|
270
|
|
|||||
Impairment of investment in unconsolidated affiliate
|
—
|
|
|
—
|
|
|
(308
|
)
|
|
—
|
|
|
(308
|
)
|
|||||
Gains on acquisitions
|
—
|
|
|
—
|
|
|
83
|
|
|
—
|
|
|
83
|
|
|||||
Losses on interest rate derivatives
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
—
|
|
|
(12
|
)
|
|||||
Other, net
|
—
|
|
|
—
|
|
|
126
|
|
|
—
|
|
|
126
|
|
|||||
Income before income tax benefit
|
554
|
|
|
705
|
|
|
814
|
|
|
(1,417
|
)
|
|
656
|
|
|||||
Income tax benefit
|
—
|
|
|
—
|
|
|
(255
|
)
|
|
—
|
|
|
(255
|
)
|
|||||
Net income from continuing operations
|
554
|
|
|
705
|
|
|
1,069
|
|
|
(1,417
|
)
|
|
911
|
|
|||||
Net income attributable to discontinued operations
|
—
|
|
|
—
|
|
|
(462
|
)
|
|
—
|
|
|
(462
|
)
|
|||||
Net income
|
554
|
|
|
705
|
|
|
607
|
|
|
(1,417
|
)
|
|
449
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
41
|
|
|
—
|
|
|
41
|
|
|||||
Less: Net loss attributable to predecessor
|
—
|
|
|
—
|
|
|
(134
|
)
|
|
—
|
|
|
(134
|
)
|
|||||
Net income attributable to partners
|
$
|
554
|
|
|
$
|
705
|
|
|
$
|
700
|
|
|
$
|
(1,417
|
)
|
|
$
|
542
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other comprehensive income
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
4
|
|
Comprehensive income
|
554
|
|
|
705
|
|
|
611
|
|
|
(1,417
|
)
|
|
453
|
|
|||||
Comprehensive income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
41
|
|
|
—
|
|
|
41
|
|
|||||
Comprehensive loss attributable to predecessor
|
—
|
|
|
—
|
|
|
(134
|
)
|
|
—
|
|
|
(134
|
)
|
|||||
Comprehensive income attributable to partners
|
$
|
554
|
|
|
$
|
705
|
|
|
$
|
704
|
|
|
$
|
(1,417
|
)
|
|
$
|
546
|
|
|
Year Ended December 31, 2018
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash flows provided by operating activities
|
$
|
4,041
|
|
|
$
|
1,521
|
|
|
$
|
5,641
|
|
|
$
|
(3,644
|
)
|
|
$
|
7,559
|
|
Cash flows used in investing activities
|
(3,408
|
)
|
|
(1,519
|
)
|
|
(5,619
|
)
|
|
3,644
|
|
|
(6,902
|
)
|
|||||
Cash flows used in financing activities
|
(633
|
)
|
|
—
|
|
|
(2,675
|
)
|
|
—
|
|
|
(3,308
|
)
|
|||||
Net increase in cash and cash equivalents of discontinued operations
|
—
|
|
|
—
|
|
|
2,734
|
|
|
—
|
|
|
2,734
|
|
|||||
Change in cash
|
—
|
|
|
2
|
|
|
81
|
|
|
—
|
|
|
83
|
|
|||||
Cash at beginning of period
|
—
|
|
|
(2
|
)
|
|
337
|
|
|
—
|
|
|
335
|
|
|||||
Cash at end of period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
418
|
|
|
$
|
—
|
|
|
$
|
418
|
|
|
Year Ended December 31, 2017
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash flows provided by operating activities
|
$
|
2,564
|
|
|
$
|
1,047
|
|
|
$
|
5,013
|
|
|
$
|
(3,807
|
)
|
|
$
|
4,817
|
|
Cash flows used in investing activities
|
(2,240
|
)
|
|
(1,368
|
)
|
|
(5,811
|
)
|
|
3,807
|
|
|
(5,612
|
)
|
|||||
Cash flows provided by (used in) financing activities
|
(324
|
)
|
|
277
|
|
|
619
|
|
|
—
|
|
|
572
|
|
|||||
Net increase in cash and cash equivalents of discontinued operations
|
—
|
|
|
—
|
|
|
93
|
|
|
—
|
|
|
93
|
|
|||||
Change in cash
|
—
|
|
|
(44
|
)
|
|
(86
|
)
|
|
—
|
|
|
(130
|
)
|
|||||
Cash at beginning of period
|
—
|
|
|
42
|
|
|
423
|
|
|
—
|
|
|
465
|
|
|||||
Cash at end of period
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
337
|
|
|
$
|
—
|
|
|
$
|
335
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash flows provided by operating activities
|
$
|
553
|
|
|
$
|
675
|
|
|
$
|
4,395
|
|
|
$
|
(1,417
|
)
|
|
$
|
4,206
|
|
Cash flows used in investing activities
|
(976
|
)
|
|
(2,400
|
)
|
|
(6,998
|
)
|
|
1,417
|
|
|
(8,957
|
)
|
|||||
Cash flows provided by financing activities
|
423
|
|
|
1,729
|
|
|
2,865
|
|
|
—
|
|
|
5,017
|
|
|||||
Net decrease in cash and cash equivalents of discontinued operations
|
—
|
|
|
—
|
|
|
(385
|
)
|
|
—
|
|
|
(385
|
)
|
|||||
Change in cash
|
—
|
|
|
4
|
|
|
(123
|
)
|
|
—
|
|
|
(119
|
)
|
|||||
Cash at beginning of period
|
—
|
|
|
38
|
|
|
546
|
|
|
—
|
|
|
584
|
|
|||||
Cash at end of period
|
$
|
—
|
|
|
$
|
42
|
|
|
$
|
423
|
|
|
$
|
—
|
|
|
$
|
465
|
|
Advanced Meter Solutions LLC, a Delaware limited liability company
|
Advantage Diesel LLC, a Idaho limited liability company
|
Aqua-ETC Water Solutions, LLC, a Delaware limited liability company
|
Arguelles Pipeline S de R.L. DE C.V., a Mexico SRL
|
Atlantic Petroleum Company LLC, a Delaware limited liability company
|
Atlantic Refining & Marketing LLC, a Delaware limited liability company
|
Bakken Gathering LLC, a Delaware limited liability company
|
Bakken Holdings Company LLC, a Delaware limited liability company
|
Bakken Pipeline Investments LLC, a Delaware limited liability company
|
Bayou Bridge Pipeline, LLC, a Delaware limited liability company
|
Bayview Refining Company, LLC, a Delaware limited liability company
|
BBP Construction Management, LLC, a Delaware limited liability company
|
Chalkley Gathering Company, LLC, a Texas limited liability company
|
Citrus Energy Services, Inc., a Delaware corporation
|
Citrus ETP Finance LLC, a Delaware limited liability company
|
Citrus, LLC, a Delaware limited liability company
|
Clean Air Action Corporation, a Delaware corporation
|
CMA Pipeline Partnership, LLC, a Texas limited liability company
|
Comanche Trail Pipeline, LLC, a Texas limited liability company
|
Connect Gas Pipeline LLC, a Delaware limited liability company
|
Consorcio Terminales LLC, a Delaware limited liability company
|
CrossCountry Citrus, LLC, a Delaware limited liability company
|
CrossCountry Energy, LLC, a Delaware limited liability company
|
Dakota Access Holdings, LLC, a Delaware limited liability company
|
Dakota Access Truck Terminals, LLC, a Delaware limited liability company
|
Dakota Access, LLC, a Delaware limited liability company
|
DAPL-ETCO Construction Management, LLC, a Delaware limited liability company
|
DAPL-ETCO Operations Management, LLC, a Delaware limited liability company
|
Dual Drive Technologies, Ltd., a Texas limited partnership
|
Eastern Gulf Crude Access, LLC, a Delaware limited liability company
|
Edwards Lime Gathering, LLC, a Delaware limited liability company
|
ELG Oil LLC, a Delaware limited liability company
|
ELG Utility LLC, a Delaware limited liability company
|
Energy Transfer (Beijing) Energy Technology Co., Ltd., a Chinese limited liability company
|
Energy Transfer Aviation LLC, a Delaware limited liability company
|
Energy Transfer Crude Oil Company, LLC, a Delaware limited liability company
|
Energy Transfer Data Center, LLC, a Delaware limited liability company
|
Energy Transfer Employee Management LLC a Delaware limited liability company
|
Energy Transfer Fuel GP, LLC, a Delaware limited liability company
|
Energy Transfer Fuel, LP, a Delaware limited partnership
|
Energy Transfer Group, L.L.C., a Texas limited liability company
|
Energy Transfer International Holdings LLC, a Delaware limited liability company
|
Energy Transfer Interstate Holdings, LLC, a Delaware limited liability company
|
Energy Transfer LNG Export, LLC, a Delaware limited liability company
|
Energy Transfer Management Holdings, LLC, a Delaware limited liability company
|
Energy Transfer Mexicana, LLC, a Delaware limited liability company
|
Energy Transfer Rail Company, LLC, a Delaware limited liability company
|
Energy Transfer Retail Power, LLC, a Delaware limited liability company
|
Energy Transfer Terminalling Company, LLC, a Delaware limited liability company
|
ET Company I, Ltd., a Texas limited partnership
|
ET Crude Oil Terminals, LLC, a Delaware limited partnership
|
ET Fuel Pipeline, L.P., a Delaware limited partnership
|
ET Rover Pipeline LLC, a Delaware limited liability company
|
ETC Bayou Bridge Holdings, LLC, a Delaware limited liability company
|
ETC China Holdings LLC, a Delaware limited liability company
|
ETC Compression, LLC, a Delaware limited liability company
|
ETC Endure Energy L.L.C., a Delaware limited liability company
|
ETC Energy Transfer, LLC, a Delaware limited liability company
|
ETC Fayetteville Express Pipeline, LLC, a Delaware limited liability company
|
ETC Fayetteville Operating Company, LLC, a Delaware limited liability company
|
ETC Gas Company, Ltd., a Texas limited partnership
|
ETC Hydrocarbons, LLC, a Texas limited liability company
|
ETC Illinois LLC, a Delaware limited liability company
|
ETC Interstate Procurement Company, LLC, a Delaware limited liability company
|
ETC Intrastate Procurement Company, LLC, a Delaware limited liability company
|
ETC Katy Pipeline, Ltd., a Texas limited partnership
|
ETC M-A Acquisition LLC, a Delaware limited liability company
|
ETC Marketing, Ltd., a Texas limited partnership
|
ETC Midcontinent Express Pipeline, L.L.C., a Delaware limited liability company
|
ETC New Mexico Pipeline, L.P., a New Mexico limited partnership
|
ETC NGL Marketing, LLC, a Texas limited liability company
|
ETC NGL Transport, LLC, a Texas limited liability company
|
ETC North Dakota Terminalling, LLC, a Delaware limited liability company
|
ETC Northeast Development, LLC, a West Virginia limited liability company
|
ETC Northeast Field Services LLC, a Delaware limited liability company
|
ETC Northeast Holdings LLC, a Delaware limited liability company
|
ETC Northeast Midstream LLC, a Delaware limited liability company
|
ETC Northeast Pipeline, LLC, a Delaware limited liability company
|
ETC Oasis GP, LLC a Texas limited liability company
|
ETC PennTex LLC, a Delaware limited liability company
|
ETC Sunoco Holdings LLC, a Pennsylvania limited liability company
|
ETC Texas Pipeline, Ltd., a Texas limited partnership
|
ETC Tiger Pipeline, LLC, a Delaware limited liability company
|
ETC Tilden System LLC, a Delaware limited liability company
|
ETC Water Solutions, LLC, a Delaware limited liability company
|
ETCO Holdings LLC, a Delaware limited liability company
|
ETP Crude LLC, a Texas limited liability company
|
ETP Holdco Corporation, a Delaware corporation
|
ETP Legacy LP, a Delaware limited partnership
|
ETP Retail Holdings, LLC, a Delaware limited liability company
|
Evergreen Assurance, LLC, a Delaware limited liability company
|
Evergreen Capital Holdings, LLC, a Delaware limited liability company
|
Evergreen Resources Group, LLC, a Delaware limited liability company
|
Explorer Pipeline Company, a Delaware corporation
|
Fayetteville Express Pipeline LLC, a Delaware limited liability company
|
FEP Arkansas Pipeline, LLC, an Arkansas limited liability company
|
Five Dawaco, LLC, a Texas limited liability company
|
Florida Gas Transmission Company, LLC, a Delaware limited liability company
|
FLST LLC, a Delaware limited liability company
|
FrontStreet Hugoton LLC, a Delaware limited liability company
|
Galveston Bay Gathering, LLC, a Texas limited liability company
|
Gulf States Transmission LLC, a Louisiana limited liability company
|
Helios Assurance Company, a Limited Bermuda other
|
Heritage ETC GP, L.L.C., a Delaware limited liability company
|
Heritage ETC, L.P., a Delaware limited partnership
|
Heritage Holdings, Inc., a Delaware corporation
|
Houston Pipe Line Company LP, a Delaware limited partnership
|
HP Houston Holdings, L.P., a Delaware limited partnership
|
HPL Asset Holdings LP, a Delaware limited partnership
|
HPL Consolidation LP, a Delaware limited partnership
|
HPL GP, LLC, a Delaware limited liability company
|
HPL Holdings GP, L.L.C., a Delaware limited liability company
|
HPL Houston Pipe Line Company, LLC, a Delaware limited liability company
|
HPL Leaseco LP, a Delaware limited partnership
|
HPL Resources Company LP, a Delaware limited partnership
|
HPL Storage GP LLC, a Delaware limited liability company
|
Inland Corporation, an Ohio corporation
|
J.C. Nolan Pipeline Co., LLC, a Delaware limited liability company
|
Japan Sun Oil Company, Ltd., a Japan other
|
Kanawha Rail LLC, a Delaware limited liability company
|
LA GP, LLC, a Texas limited liability company
|
La Grange Acquisition, L.P., a Texas limited partnership
|
LaGrange-ETCOP Operating Company, LLC, a Delaware limited liability company
|
Lake Charles Exports, LLC, a Delaware limited liability company
|
Lake Charles LNG Company, LLC, Delaware limited liability company
|
Lake Charles LNG Export Company, LLC, a Delaware limited liability company
|
Lavan Petroleum Company (LAPCO), an Iran, Islamic Republic of other
|
Lee 8 Storage Partnership, a Delaware limited partnership
|
LG PL, LLC, a Texas limited liability company
|
LGM, LLC, a Texas limited liability company
|
Liberty Pipeline Group, LLC, a Delaware limited liability company
|
Libre Insurance Company, Ltd., a Bermuda corporation
|
LJL, LLC, a West Virginia limited liability company
|
Loadout LLC, a Delaware limited liability company
|
Lobo Pipeline Company LLC, a Delaware limited liability company
|
Lone Star NGL Asset GP LLC, a Delaware limited liability company
|
Lone Star NGL Asset Holdings II LLC, a Delaware limited liability company
|
Lone Star NGL Asset Holdings LLC, a Delaware limited liability company
|
Lone Star NGL Development LP, a Delaware limited partnership
|
Lone Star NGL Fractionators LLC, a Delaware limited liability company
|
Lone Star NGL Hattiesburg LLC, a Delaware limited liability company
|
Lone Star NGL LLC, a Delaware limited liability company
|
Lone Star NGL Marketing LLC, a Delaware limited liability company
|
Lone Star NGL Mont Belvieu GP LLC, a Delaware limited liability company
|
Lone Star NGL Mont Belvieu LP, a Delaware limited partnership
|
Lone Star NGL Mont Belvieu Pipelines LLC, a Delaware limited liability company
|
Lone Star NGL Pipeline LP, a Delaware limited partnership
|
Lone Star NGL Product Services LLC, a Delaware limited liability company
|
Lone Star NGL Refinery Services LLC, a Delaware limited liability company
|
Lone Star NGL Sea Robin LLC, a Delaware limited liability company
|
Lugrasa, S.A., a Panama corporation
|
Materials Handling Solutions LLC, a Delaware limited liability company
|
Mi Vida JV LLC, a Delaware limited liability company
|
Mid Valley Pipeline Company LLC, an Ohio limited liability company
|
Midcontinent Express Pipeline LLC, a Delaware limited liability company
|
Midland Terminal LLC, a Delaware limited liability company
|
Midstream Gas Services, LLC, a Texas limited liability company
|
Midstream Logistics, LLC, a Delaware limited liability company
|
Midwest Connector Capital Company LLC, a Delaware limited liability company
|
Oasis Pipe Line Finance Company, a Delaware corporation
|
Oasis Pipeline, LP, a Texas limited partnership
|
Ohio River System LLC, a Delaware limited liability company
|
Oil Casualty Insurance, Ltd., a Bermuda Limited Company
|
Oil Insurance Limited, Bermuda limited company
|
Old Ocean Pipeline, LLC, a Texas limited liability company
|
Orbit Gulf Coast NGL Exports, LLC, a Delaware limited liability company
|
Pacific Ethanol Central, LLC, a Delaware limited liability company
|
Pan Gas Storage LLC , a Delaware limited liability company
|
Panhandle Eastern Pipe Line Company, LP, a Delaware limited partnership
|
Panhandle Energy LNG Services, LLC, a Delaware limited liability company
|
Panhandle Storage LLC, a Delaware limited liability company
|
PEI Power II, LLC, a Pennsylvania limited liability company
|
PEI Power LLC, a Pennsylvania limited liability company
|
Pelico Pipeline, LLC, a Delaware limited liability company
|
Penn Virginia Operating Co., LLC, a Delaware limited liability company
|
PEPL Real Estate, LLC, a Delaware limited liability company
|
Permian Express Partners LLC, a Delaware limited liability company
|
Permian Express Partners Operating LLC, a Texas limited liability company
|
Permian Express Terminal LLC, a Delaware limited liability company
|
Permian Gulf Coast Pipeline LLC, a Delaware limited liability company
|
PES Energy Inc., a Delaware corporation
|
PES Equity Holdings, LLC, a Delaware limited liability company
|
PES Holdings, LLC, a Delaware limited liability company
|
PG Energy, Inc., a Pennsylvania corporation
|
Philadelphia Energy Solutions LLC, a Delaware limited liability company
|
Philadelphia Energy Solutions Refining and Marketing LLC, a Delaware limited liability company
|
Price River Terminal, LLC, a Texas limited liability company
|
PVR Midstream JV Holdings LLC, a Delaware limited liability company
|
Ranch Westex JV LLC, a Delaware limited liability company
|
Red Bluff Express Pipeline, LLC, a Delaware limited liability company
|
Regency Crude Marketing LLC, a Delaware limited liability company
|
Regency Employees Management Holdings LLC, a Delaware limited liability company
|
Regency Energy Finance Corp., a Delaware corporation
|
Regency Energy Partners LP, a Delaware limited partnership
|
Regency ERCP LLC, a Delaware limited liability company
|
Regency Gas Services LP, a Delaware limited partnership
|
Regency GOM LLC, a Texas limited liability company
|
Regency GP LLC, a Delaware limited liability company
|
Regency GP LP, a Delaware limited partnership
|
Regency Haynesville Intrastate Gas LLC, a Delaware limited liability company
|
Regency Hydrocarbons LLC, an Oklahoma limited liability company
|
Regency Intrastate Gas LP, a Delaware limited partnership
|
Regency Laverne LLC, an Oklahoma limited liability company
|
Regency Marcellus Gas Gathering LLC, a Delaware limited liability company
|
Regency Mi Vida LLC, a Delaware limited liability company
|
Regency NEPA Gas Gathering LLC, a Texas limited liability company
|
Regency OLP GP LLC, a Delaware limited liability company
|
Regency Pipeline LLC, a Delaware limited liability company
|
Regency Quitman Gathering LLC, a Delaware limited liability company
|
Regency Ranch JV LLC, a Delaware limited liability company
|
Regency Texas Pipeline LLC, a Delaware limited liability company
|
Regency Utica Gas Gathering LLC, a Delaware limited liability company
|
Regency Utica Holdco LLC, a Delaware limited liability company
|
Regency Vaughn Gathering LLC, a Texas limited liability company
|
RGP Marketing LLC, a Texas limited liability company
|
RIGS GP LLC, a Delaware limited liability company
|
RIGS Haynesville Partnership Co., a Delaware partnership
|
Rover Pipeline LLC, a Delaware limited liability company
|
RSS Water Services LLC, a Delaware limited liability company
|
Sea Robin Pipeline Company, LLC , a Delaware limited liability company
|
SEC Energy Products & Services, L.P., a Texas limited partnership
|
SEC General Holdings, LLC, a Texas limited liability company
|
Southern Union Gas Company, Inc., a Texas corporation
|
Southern Union Panhandle LLC, a Delaware limited liability company
|
SU Gas Services Operating Company, Inc., a Delaware corporation
|
SU Holding Company, Inc., a Delaware corporation
|
Sun Atlantic Refining and Marketing B.V., a Netherlands other
|
Sun Atlantic Refining and Marketing B.V., LLC, a Delaware limited liability company
|
Sun Atlantic Refining and Marketing Company, LLC, a Delaware limited liability company
|
Sun Canada, Inc., a Delaware corporation
|
Sun International Limited, a Bermuda corporation
|
Sun Lubricants and Specialty Products Inc., a Quebec corporation
|
Sun Mexico One, Inc., a Delaware corporation
|
Sun Mexico Two, Inc., a Delaware corporation
|
Sun Oil Export Company, a Delaware corporation
|
Sun Pipe Line Company of Delaware LLC, a Delaware limited liability company
|
Sun Transport, LLC, a Pennsylvania limited liability company
|
Sunoco (R&M), LLC, a Pennsylvania limited liability company
|
Sunoco de Mexico, S.A. de C.V., a Mexico other
|
Sunoco GP LLC, a Delaware limited liability company
|
Sunoco Logistics Partners GP LLC, a Delaware limited liability company
|
Sunoco Logistics Partners Operations GP LLC, a Delaware limited liability company
|
Sunoco Logistics Partners Operations L.P., a Delaware limited partnership
|
Sunoco LP, a Delaware limited partnership
|
Sunoco Midland Gathering LLC, a Texas limited liability company
|
Sunoco Midland Terminal LLC, a Texas limited liability company
|
Sunoco Overseas, Inc., a Delaware corporation
|
Sunoco Partners Marketing & Terminals L.P., a Texas limited partnership
|
Sunoco Partners NGL Facilities LLC, a Delaware limited liability company
|
Sunoco Partners Operating LLC, a Delaware limited liability company
|
Sunoco Partners Real Estate Acquisition LLC, a Delaware limited liability company
|
Sunoco Partners Rockies LLC, a Delaware limited liability company
|
Sunoco Pipeline Acquisition LLC, a Delaware limited liability company
|
Sunoco Pipeline L.P., a Texas limited partnership
|
Sunoco Receivables LLC, a Delaware limited liability company
|
Sweeney Gathering, L.P., a Texas limited liability company
|
SXL Acquisition Sub LLC, a Delaware limited liability company
|
TETC, LLC, a Texas limited liability company
|
Texas Energy Transfer Company, Ltd., a Texas limited partnership
|
Texas Energy Transfer Power, LLC, a Texas limited liability company
|
The Energy Transfer/Sunoco Foundation, a Pennsylvania non-profit
|
Toney Fork LLC, a Delaware limited liability company
|
Trade Star Holdings, LLC, a Delaware limited liability company
|
Trade Star Leasing LLC, a Idaho limited liability company
|
Trade Star Properties LLC, a Idaho limited liability company
|
Trade Star Williston, LLC, a Idaho limited liability company
|
Trade Star, LLC, a Idaho limited liability company
|
Trans-Pecos Pipeline, LLC, a Texas limited liability company
|
Transwestern Pipeline Company, LLC, a Delaware limited liability company
|
Trunkline Field Services LLC, a Delaware limited liability company
|
Trunkline Gas Company, LLC, a Delaware limited liability company
|
Trunkline LNG Holdings LLC, a Delaware limited liability company
|
USA Compression GP, LLC, a Delaware limited liability company
|
USA Compression Management Services, LLC, a Delaware limited liability company
|
Venezoil, C.A., a Venezuela other
|
Vista Mar Pipeline, LLC, a Texas limited liability company
|
Waha Express Pipeline, LLC, a Delaware limited liability company
|
West Shore Pipe Line Company, a Delaware corporation
|
West Texas Gulf Pipe Line Company LLC, a Delaware limited liability company
|
Westex Energy LLC, a Delaware limited liability company
|
WGP-KHC, LLC, a Delaware limited liability company
|
Whiskey Bay Gathering Company, LLC, a Delaware limited liability company
|
Wolverine Pipe Line Company, a Delaware corporation
|
Yellowstone Pipe Line Company, a Delaware corporation
|
Allied Energy Company LLC, an Alabama limited liability company
|
Aloha Petroleum LLC, a Delaware limited liability company
|
Aloha Petroleum, Ltd., a Hawaii Corporation
|
Cal’s New SSP Beverage, LLC, a Texas limited liability company
|
Cal’s New T&C Beverage, LLC, a Texas limited liability company
|
Coastline Transportation, Inc., a Texas corporation
|
Direct Fuels LLC, a Delaware limited liability company
|
Quick Stuff of Texas, Inc., a Texas Corporation
|
Sandford Energy, LLC, a Texas limited liability company
|
Sandford Fuels, LLC, a Texas limited liability company
|
Sandford Oil Company, Inc., a Texas corporation
|
Sandford Oil South Texas, Inc., a Texas corporation
|
Sandford Petroleum, Inc., a Texas corporation
|
Sandford Transportation, LLC, a Texas limited liability company
|
SSP BevCo I LLC, a Texas limited liability company
|
SSP BevCo II LLC, a Texas limited liability company
|
SSP Beverage, LLC, a Texas limited liability company
|
Stripes Acquisition LLC, a Texas limited liability company
|
Sunmarks, LLC, a Delaware limited liability company
|
Sunoco Caddo LLC, a Delaware limited liability company
|
Sunoco Finance Corp., a Delaware corporation
|
Sunoco NLR LLC, a Delaware limited liability company
|
Sunoco Property Company LLC, a Delaware limited liability company
|
Sunoco Refined Products LLC, a Delaware limited liability company
|
Sunoco Retail LLC, a Pennsylvania limited liability company
|
Sunoco, LLC, a Delaware limited liability company
|
TCFS Holdings, Inc. a Texas corporation
|
TND Beverage, LLC, a Texas limited liability company
|
Town & Country Food Stores, Inc., a Texas corporation
|
Western Transportation, Inc., a Texas corporation
|
CDM Environmental & Technical Services, LLC, a Delaware limited liability company
|
CDM Resource Management LLC, a Delaware limited liability company
|
USA Compression Finance, Corp., a Delaware corporation
|
USA Compression Partners, LLC, a Delaware limited liability company
|
USAC Leasing, LLC, a Delaware limited liability company
|
USAC OpCo 2, LLC, a Texas limited liability company
|
USAC Leasing 2, LLC, a Texas limited liability company
|
1.
|
I have reviewed this annual report on Form 10-K of Energy Transfer Operating, L.P. (the "registrant");
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize, and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
/s/ Kelcy L. Warren
|
|
Kelcy L. Warren
|
|
Chief Executive Officer
|
|
1.
|
I have reviewed this annual report on Form 10-K of Energy Transfer Operating, L.P. (the "registrant");
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize, and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
/s/ Thomas E. Long
|
|
Thomas E. Long
|
|
Chief Financial Officer
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
/s/ Kelcy L. Warren
|
|
Kelcy L. Warren
|
|
Chief Executive Officer
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
/s/ Thomas E. Long
|
|
Thomas E. Long
|
|
Chief Financial Officer
|
|