☒
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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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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Trading Symbol(s)
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Name of each exchange on which registered
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7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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ETPprC
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New York Stock Exchange
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7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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ETPprD
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New York Stock Exchange
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7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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ETPprE
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New York Stock Exchange
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7.500% Senior Notes due 2020
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ETP 20
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New York Stock Exchange
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4.250% Senior Notes due 2023
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ETP 23
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New York Stock Exchange
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5.875% Senior Notes due 2024
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ETP 24
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New York Stock Exchange
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5.500% Senior Notes due 2027
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ETP 27
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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
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Dakota Access
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Dakota Access, LLC, a less than wholly-owned subsidiary of ETO
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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, the parent company of ETO
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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 and is a wholly-owned subsidiary of ETO
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ETC Sunoco
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ETC Sunoco Holdings LLC (formerly, Sunoco Inc.), a wholly-owned subsidiary of ETO
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ETC Tiger
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ETC Tiger Pipeline, LLC, a wholly-owned subsidiary of ETO
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ETCO
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Energy Transfer Crude Oil Company, LLC, a less than wholly-owned subsidiary of ETO
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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, a wholly owned subsidiary of ETO
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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, a wholly-owned subsidiary of Citrus
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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, a wholly-owned subsidiary of ETO
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HFOTCO
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Houston Fuel Oil Terminal Company, a wholly-owned subsidiary of ETO, which owns the Houston Terminal
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HPC
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RIGS Haynesville Partnership Co., a wholly-owned subsidiary of ETO
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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), a wholly-owned subsidiary of ETO
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LCL
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Lake Charles LNG Export Company, LLC, a wholly-owned subsidiary of ETO
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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, a wholly-owned subsidiary of ETO
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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, a wholly-owned subsidiary of ETO
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MMBls
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million barrels
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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, a less than wholly-owned subsidiary of ETO
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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, wholly-owned by ETO
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PCBs
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polychlorinated biphenyls
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PennTex
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PennTex Midstream Partners, LP, acquired by ETO during 2016-2017 and now a wholly-owned subsidiary named ETC PennTex LLC
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PEP
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Permian Express Partners LLC, a less than wholly-owned subsidiary of ETO
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PES
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Philadelphia Energy Solutions Refining and Marketing LLC, non-controlling interest owned by ETO
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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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Preferred Unitholders
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Unitholders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units and Series G Preferred Units, collectively
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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, a wholly-owned subsidiary of ETO
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Retail Holdings
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ETP Retail Holdings, LLC, a wholly-owned subsidiary of ETO
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RIGS
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Regency Intrastate Gas System, a wholly-owned subsidiary of ETO
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Rover
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Rover Pipeline LLC, a less than wholly-owned subsidiary of ETO
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Sea Robin
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Sea Robin Pipeline Company, LLC, a wholly-owned subsidiary of Panhandle
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SEC
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Securities and Exchange Commission
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SemGroup
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SemGroup Corporation
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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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Series E Preferred Units
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7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Series F Preferred Units
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6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
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Series G Preferred Units
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7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
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Shell
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Royal Dutch Shell plc
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Southwest Gas
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Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage Company)
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SPLP
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Sunoco Pipeline L.P., a wholly-owned subsidiary of ETO
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Sunoco Logistics
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Sunoco Logistics Partners L.P., a wholly-owned subsidiary of ETO
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Sunoco (R&M)
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Sunoco (R&M), LLC
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Transwestern
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Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of ETO
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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 wholly-owned subsidiary of Panhandle
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Unitholders
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Preferred Unitholders and our common unitholder (Energy Transfer LP), collectively
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USAC
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USA Compression Partners, LP, a wholly-owned subsidiary of ETO
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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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•
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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 December 2019, ET completed its acquisition of Tulsa-based SemGroup Corporation in a unit and cash transaction. During the first quarter of 2020, certain of the operating assets of SemGroup were contributed to ETO, and as such, the segment and asset overviews below include those contributed SemGroup assets.
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In December 2019, ET announced a comprehensive commercial tender package which was issued to engineering, procurement and construction contractors to submit final bids for the proposed Lake Charles LNG liquefaction project being developed with Shell US LNG, LLC. The project would modify ETO’s existing LNG import facility located in Lake Charles, Louisiana to add LNG liquefaction capacity of 16.45 million tonnes per annum for expert to global markets. The commercial bids are expected to be received in the second quarter of 2020.
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In connection with the acquisition of SemGroup and to provide shippers with further access to markets along the Gulf Coast through the Houston Ship Channel, ET announced the construction of the Ted Collins pipeline, a 75-mile crude line that will connect Houston Terminal, which was recently acquired in the SemGroup acquisition, to the Nederland terminal. The pipeline is expected to be in service in 2021 and will have an initial capacity of 500 MBbls/d.
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approximately 4,515 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 50 MMBbls; 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 13 MMBbls.
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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 7.4% 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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2.9
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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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108
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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 providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the Waha Hub near Pecos, Texas, the Maypearl Hub in Central Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.
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•
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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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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 108-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. 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)
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Florida Gas Transmission
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50
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%
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5,362
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3.5
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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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—
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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
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73.4
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Trunkline Gas Company
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100
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%
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2,231
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0.9
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13.0
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Tiger Pipeline
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100
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%
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197
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2.4
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—
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Fayetteville Express Pipeline
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50
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%
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185
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2.0
|
|
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—
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Sea Robin Pipeline
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100
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%
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785
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2.0
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|
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—
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Stingray Pipeline
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100
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%
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302
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|
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0.4
|
|
|
—
|
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Rover Pipeline
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32.6
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%
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|
713
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|
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3.25
|
|
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—
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Midcontinent Express Pipeline
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50
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%
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512
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|
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1.8
|
|
|
—
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Gulf States
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100
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%
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10
|
|
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0.1
|
|
|
—
|
|
(1)
|
Natural gas storage assets are owned by Southwest Gas.
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•
|
Florida Gas Transmission Pipeline (“FGT”) has mainline capacity of 3.5 Bcf/d and approximately 5,362 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 approximately 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.
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•
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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 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.
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•
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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.
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•
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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.
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•
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Tiger Pipeline is a bi-directional system that extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, interconnecting with multiple interstate pipelines.
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•
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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.
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•
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Sea Robin Pipeline’s system consists of two offshore Louisiana natural gas supply pipelines extending 120 miles into the Gulf of Mexico.
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•
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Stingray Pipeline is an interstate natural gas pipeline system with related assets located in the western Gulf of Mexico and Johnson Bayou, Louisiana.
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•
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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.
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•
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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.
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•
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Gulf States Transmission is a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
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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
|
|
2,740
|
|
Midcontinent Region
|
|
1,385
|
|
Eastern Region
|
|
200
|
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•
|
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 gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines to Lone Star.
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•
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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.
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•
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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 1.4 Bcf/d.
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•
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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.
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•
|
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.
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•
|
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.
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•
|
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 2.4 Bcf/d and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.
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•
|
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.
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•
|
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.
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•
|
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 and the STACK in central Oklahoma. 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 sixteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray, Gray, Rose Valley, and Hopeton) with an aggregate capacity of approximately 1.4 Bcf/d.
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•
|
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.
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•
|
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.
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•
|
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.
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•
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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.
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•
|
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)
|
|
NGL Fractionation / Processing Capacity
(MBbls/d)
|
|
Working Storage Capacity
(MBbls)
|
|||
Liquids Pipelines:
|
|
|
|
|
|
|
|||
Lone Star Express
|
|
535
|
|
|
—
|
|
|
—
|
|
West Texas Gateway Pipeline
|
|
512
|
|
|
—
|
|
|
—
|
|
Lone Star
|
|
1,617
|
|
|
—
|
|
|
—
|
|
Mariner East
|
|
670
|
|
|
—
|
|
|
—
|
|
Mariner South
|
|
97
|
|
|
—
|
|
|
—
|
|
Mariner West
|
|
395
|
|
|
—
|
|
|
—
|
|
White Cliffs Pipeline(3)
|
|
527
|
|
|
—
|
|
|
—
|
|
Other NGL Pipelines
|
|
162
|
|
|
—
|
|
|
—
|
|
Liquids Fractionation and Services Facilities:
|
|
|
|
|
|
|
|||
Mont Belvieu Facilities
|
|
182
|
|
|
790
|
|
|
50,000
|
|
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
|
|
|
6,000
|
|
Inkster
|
|
—
|
|
|
—
|
|
|
860
|
|
Refined Products Pipelines:
|
|
|
|
|
|
|
|||
Eastern region pipelines
|
|
957
|
|
|
—
|
|
|
—
|
|
Midcontinent region pipelines
|
|
349
|
|
|
—
|
|
|
—
|
|
Southwest region pipelines
|
|
876
|
|
|
—
|
|
|
—
|
|
Inland Pipeline
|
|
581
|
|
|
—
|
|
|
—
|
|
JC Nolan Pipeline
|
|
502
|
|
|
—
|
|
|
—
|
|
Refined Products Terminals:
|
|
|
|
|
|
|
|||
Eagle Point
|
|
—
|
|
|
—
|
|
|
7,000
|
|
Marcus Hook Industrial Complex
|
|
—
|
|
|
—
|
|
|
1,000
|
|
Marcus Hook Tank Farm
|
|
—
|
|
|
—
|
|
|
2,000
|
|
Marketing Terminals
|
|
—
|
|
|
—
|
|
|
8,000
|
|
JC Nolan Terminal
|
|
—
|
|
|
—
|
|
|
134
|
|
(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.
|
(3)
|
The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
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•
|
The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline, with throughput capacity of approximately 500 MBbls/d, that delivers mixed NGLs from processing plants in the
|
•
|
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d.
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•
|
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 East pipeline has a throughput capacity of approximately 345 MBbls/d.
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•
|
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 and has a throughput capacity of approximately 200 MBbls/d.
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•
|
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 and has a throughput capacity of approximately 50 MBbls/d.
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•
|
The White Cliffs NGL pipeline, which we have 51% ownership interest in and which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, transports NGLs produced in the DJ Basin to Cushing, where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 40 MBbls/d.
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•
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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.
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•
|
Our Mont Belvieu storage facility is an integrated liquids storage facility with approximately 50 MMBbls 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.
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•
|
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 was placed in service in the first quarter of 2020, and Fractionator VIII is currently under construction and is scheduled to be operational by the second quarter of 2021.
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•
|
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.
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•
|
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.
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•
|
The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 MMBbls 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 MMBbls 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 1.2 MMBbls 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.
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•
|
The Marcus Hook Industrial Complex includes fractionation, terminalling and storage assets, with a capacity of approximately 2 MMBbls of NGL storage capacity in underground caverns, 4 MMBbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMBbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel,
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•
|
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 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.
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•
|
The Eastern region refined products pipelines consist of approximately 615 miles of 6-inch to 16-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 180 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
|
•
|
The midcontinent region refined products pipelines primarily consist of approximately 296 miles of 3-inch to 12-inch refined products pipelines in Ohio and approximately 53 miles of 6-inch and 8-inch refined products pipeline in Michigan.
|
•
|
The Southwest region refined products pipelines are located in Eastern Texas and consist primarily of approximately 876 miles of 8-inch diameter refined products pipeline.
|
•
|
The Inland refined products pipeline is approximately 580 miles of pipeline in Ohio, consisting of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 206 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 135 miles of 8-inch diameter refined products pipeline in western Ohio, and 168 miles of 6-inch diameter refined products pipeline in Northeast Ohio.
|
•
|
The JC Nolan Pipeline is a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, which transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and was placed into service in July 2019 and has a throughput capacity of approximately 36 MBbls/d.
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•
|
We have approximately 35 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls 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 7 MMBbls, 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 MMBbls of refined products storage. The terminal receives and delivers refined products via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.
|
•
|
The JC Nolan Terminal, located in Midland, Texas, is a joint venture between a wholly-owned entity of the Partnership and wholly-owned entity of Sunoco LP, which provides diesel fuel storage that was placed into service in August 2019.
|
•
|
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 1,055-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; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-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
|
%
|
|
1,172
|
|
|
—
|
|
Energy Transfer Crude Oil Pipeline
|
|
36.4
|
%
|
|
744
|
|
|
—
|
|
Bayou Bridge Pipeline
|
|
60
|
%
|
|
212
|
|
|
—
|
|
Permian Express Pipelines
|
|
87.7
|
%
|
|
1,712
|
|
|
—
|
|
Wattenberg Oil Trunkline
|
|
100
|
%
|
|
75
|
|
|
360
|
|
White Cliffs Pipeline(2)
|
|
51
|
%
|
|
527
|
|
|
100
|
|
Maurepas Pipeline
|
|
51
|
%
|
|
106
|
|
|
—
|
|
Other Crude Oil Pipelines
|
|
100
|
%
|
|
6,222
|
|
|
—
|
|
Nederland Terminal
|
|
100
|
%
|
|
—
|
|
|
29,000
|
|
Fort Mifflin Terminal
|
|
100
|
%
|
|
—
|
|
|
3,175
|
|
Eagle Point Terminal
|
|
100
|
%
|
|
—
|
|
|
1,300
|
|
Midland Terminal
|
|
100
|
%
|
|
—
|
|
|
2,000
|
|
Marcus Hook Industrial Complex
|
|
100
|
%
|
|
—
|
|
|
1,000
|
|
Houston Terminal
|
|
100
|
%
|
|
—
|
|
|
18,200
|
|
Cushing Facility
|
|
100
|
%
|
|
—
|
|
|
7,600
|
|
Patoka, Illinois Terminal
|
|
87.7
|
%
|
|
—
|
|
|
2,000
|
|
(1)
|
Miles of pipeline as reported to PHMSA.
|
(2)
|
The White Cliffs Pipeline consists of two parallel, 12-inch common carrier crude oil pipelines: one crude oil pipeline and one NGL pipeline.
|
•
|
Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,916 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 consists of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, which went into service 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, Permian Express 4, which became operational in May 2019, 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.
|
•
|
White Cliffs Pipeline. White Cliffs Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, owns a12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.
|
•
|
Maurepas Pipeline. The Maurepas Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.
|
•
|
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 29 MMBbls 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 1.3 MMBbls 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 MMBbls of crude oil storage, a combined 20 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 MMBbls.
|
•
|
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 MMBbls of crude oil storage.
|
•
|
Houston Terminal. The Houston Terminal, which was acquired by ET in the SemGroup acquisition and contributed to ETO in February 2020, consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.
|
•
|
Cushing Facilities. The Cushing Facility, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, has approximately 7.6 MMBbls crude oil storage, of which 5.6 MMBbls are leased to customer and 2.0 MMBbls are available for crude oil operations, blending and marketing activities. The storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and two-way connections with all of the other major storage terminals in Cushing. The Cushing terminal also includes truck unloading facilities.
|
•
|
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;
|
•
|
537 independently operated consignment locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;
|
•
|
6,742 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
|
•
|
2,581 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
|
|
516,674
|
|
|
3,031
|
|
|
—
|
|
|
—
|
|
|
516,674
|
|
|
3,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Large horsepower
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
>400 and <1,000
|
|
426,384
|
|
|
730
|
|
|
9,000
|
|
|
15
|
|
|
435,384
|
|
|
745
|
|
>1,000
|
|
2,739,910
|
|
|
1,690
|
|
|
47,500
|
|
|
19
|
|
|
2,787,410
|
|
|
1,709
|
|
Total large horsepower
|
|
3,166,294
|
|
|
2,420
|
|
|
56,500
|
|
|
34
|
|
|
3,222,794
|
|
|
2,454
|
|
Total horsepower
|
|
3,682,968
|
|
|
5,451
|
|
|
56,500
|
|
|
34
|
|
|
3,739,468
|
|
|
5,485
|
|
(1)
|
As of December 31, 2019, USAC had 56,500 large horsepower compression units on order for delivery during 2020.
|
•
|
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 crude oil, 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 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,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
54,032
|
|
|
$
|
54,087
|
|
|
$
|
40,523
|
|
|
$
|
31,792
|
|
|
$
|
36,096
|
|
Operating income
|
7,285
|
|
|
5,402
|
|
|
2,765
|
|
|
1,975
|
|
|
2,341
|
|
|||||
Income from continuing operations
|
5,186
|
|
|
4,039
|
|
|
2,952
|
|
|
911
|
|
|
1,371
|
|
|||||
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
||||||||||
Assets held for sale
|
—
|
|
|
—
|
|
|
3,313
|
|
|
3,588
|
|
|
3,681
|
|
|||||
Total assets
|
98,525
|
|
|
88,442
|
|
|
86,484
|
|
|
78,984
|
|
|
71,117
|
|
|||||
Liabilities associated with assets held for sale
|
—
|
|
|
—
|
|
|
75
|
|
|
48
|
|
|
42
|
|
|||||
Long-term debt, less current maturities
|
50,334
|
|
|
37,853
|
|
|
36,971
|
|
|
36,251
|
|
|
30,505
|
|
|||||
Total equity
|
35,307
|
|
|
36,621
|
|
|
36,967
|
|
|
28,938
|
|
|
29,968
|
|
|||||
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
||||||||||
Maintenance (accrual basis) (1)
|
652
|
|
|
510
|
|
|
479
|
|
|
474
|
|
|
550
|
|
|||||
Growth (accrual basis) (1)
|
4,602
|
|
|
5,120
|
|
|
5,601
|
|
|
5,775
|
|
|
8,046
|
|
|||||
Cash paid for acquisitions
|
7
|
|
|
429
|
|
|
583
|
|
|
1,398
|
|
|
964
|
|
(1)
|
Maintenance and growth capital expenditures include Sunoco LP’s capital expenditures related to discontinued operations for the years ended December 31, 2016 and 2015.
|
•
|
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.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
999
|
|
|
$
|
927
|
|
|
$
|
72
|
|
Interstate transportation and storage
|
1,792
|
|
|
1,680
|
|
|
112
|
|
|||
Midstream
|
1,599
|
|
|
1,627
|
|
|
(28
|
)
|
|||
NGL and refined products transportation and services
|
2,663
|
|
|
1,979
|
|
|
684
|
|
|||
Crude oil transportation and services
|
2,949
|
|
|
2,330
|
|
|
619
|
|
|||
Investment in Sunoco LP
|
665
|
|
|
638
|
|
|
27
|
|
|||
Investment in USAC
|
420
|
|
|
289
|
|
|
131
|
|
|||
All other
|
104
|
|
|
76
|
|
|
28
|
|
|||
Total Segment Adjusted EBITDA
|
11,191
|
|
|
9,546
|
|
|
1,645
|
|
|||
Depreciation, depletion and amortization
|
(3,124
|
)
|
|
(2,843
|
)
|
|
(281
|
)
|
|||
Interest expense, net of interest capitalized
|
(2,257
|
)
|
|
(1,709
|
)
|
|
(548
|
)
|
|||
Impairment losses
|
(74
|
)
|
|
(431
|
)
|
|
357
|
|
|||
Gains (losses) on interest rate derivatives
|
(241
|
)
|
|
47
|
|
|
(288
|
)
|
|||
Non-cash compensation expense
|
(111
|
)
|
|
(105
|
)
|
|
(6
|
)
|
|||
Unrealized losses on commodity risk management activities
|
(4
|
)
|
|
(11
|
)
|
|
7
|
|
|||
Inventory valuation adjustments
|
79
|
|
|
(85
|
)
|
|
164
|
|
|||
Losses on extinguishments of debt
|
(2
|
)
|
|
(109
|
)
|
|
107
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
(621
|
)
|
|
(655
|
)
|
|
34
|
|
|||
Equity in earnings of unconsolidated affiliates
|
298
|
|
|
344
|
|
|
(46
|
)
|
|||
Adjusted EBITDA related to discontinued operations
|
—
|
|
|
25
|
|
|
(25
|
)
|
|||
Other, net
|
252
|
|
|
30
|
|
|
222
|
|
|||
Income from continuing operations before income tax expense
|
5,386
|
|
|
4,044
|
|
|
1,342
|
|
|||
Income tax expense from continuing operations
|
(200
|
)
|
|
(5
|
)
|
|
(195
|
)
|
|||
Income from continuing operations
|
5,186
|
|
|
4,039
|
|
|
1,147
|
|
|||
Loss from discontinued operations, net of income taxes
|
—
|
|
|
(265
|
)
|
|
265
|
|
|||
Net income
|
$
|
5,186
|
|
|
$
|
3,774
|
|
|
$
|
1,412
|
|
•
|
an increase of $470 million recognized by the Partnership (excluding Sunoco LP and USAC) primarily related to an increase in long-term debt, which included $4.2 billion of senior notes issued in the ET-ETO senior note exchange (discussed below under “Description of Indebtedness”), as well as additional senior note issuances and borrowings under our revolving credit facilities;
|
•
|
an increase of $49 million recognized by USAC primarily attributable to higher overall debt balances and higher interest rates on borrowings under the credit agreement. These increases were partially offset by the decrease in borrowings under the credit agreement; and
|
•
|
an increase of $29 million recognized by Sunoco LP due to an increase in total long-term debt.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Equity in earnings of unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
148
|
|
|
$
|
141
|
|
|
$
|
7
|
|
FEP
|
59
|
|
|
55
|
|
|
4
|
|
|||
MEP
|
15
|
|
|
31
|
|
|
(16
|
)
|
|||
Other
|
76
|
|
|
117
|
|
|
(41
|
)
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
298
|
|
|
$
|
344
|
|
|
$
|
(46
|
)
|
|
|
|
|
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates(1):
|
|
|
|
|
|
||||||
Citrus
|
$
|
342
|
|
|
$
|
337
|
|
|
$
|
5
|
|
FEP
|
75
|
|
|
74
|
|
|
1
|
|
|||
MEP
|
60
|
|
|
81
|
|
|
(21
|
)
|
|||
Other
|
144
|
|
|
163
|
|
|
(19
|
)
|
|||
Total Adjusted EBITDA related to unconsolidated affiliates
|
$
|
621
|
|
|
$
|
655
|
|
|
$
|
(34
|
)
|
|
|
|
|
|
|
||||||
Distributions received from unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
178
|
|
|
$
|
171
|
|
|
$
|
7
|
|
FEP
|
73
|
|
|
68
|
|
|
5
|
|
|||
MEP
|
36
|
|
|
48
|
|
|
(12
|
)
|
|||
Other
|
96
|
|
|
110
|
|
|
(14
|
)
|
|||
Total distributions received from unconsolidated affiliates
|
$
|
383
|
|
|
$
|
397
|
|
|
$
|
(14
|
)
|
(1)
|
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
|
•
|
Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
|
•
|
Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
|
•
|
Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
|
•
|
Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Natural gas transported (BBtu/d)
|
12,442
|
|
|
10,873
|
|
|
1,569
|
|
|||
Revenues
|
$
|
3,099
|
|
|
$
|
3,737
|
|
|
$
|
(638
|
)
|
Cost of products sold
|
1,909
|
|
|
2,665
|
|
|
(756
|
)
|
|||
Segment margin
|
1,190
|
|
|
1,072
|
|
|
118
|
|
|||
Unrealized losses on commodity risk management activities
|
2
|
|
|
38
|
|
|
(36
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(190
|
)
|
|
(189
|
)
|
|
(1
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(29
|
)
|
|
(27
|
)
|
|
(2
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
25
|
|
|
32
|
|
|
(7
|
)
|
|||
Other
|
1
|
|
|
1
|
|
|
—
|
|
|||
Segment Adjusted EBITDA
|
$
|
999
|
|
|
$
|
927
|
|
|
$
|
72
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Transportation fees
|
$
|
614
|
|
|
$
|
525
|
|
|
$
|
89
|
|
Natural gas sales and other (excluding unrealized gains and losses)
|
505
|
|
|
510
|
|
|
(5
|
)
|
|||
Retained fuel revenues (excluding unrealized gains and losses)
|
50
|
|
|
59
|
|
|
(9
|
)
|
|||
Storage margin, including fees (excluding unrealized gains and losses)
|
23
|
|
|
16
|
|
|
7
|
|
|||
Unrealized losses on commodity risk management activities
|
(2
|
)
|
|
(38
|
)
|
|
36
|
|
|||
Total segment margin
|
$
|
1,190
|
|
|
$
|
1,072
|
|
|
$
|
118
|
|
•
|
an increase of $64 million in transportation fees, excluding the impact of consolidating RIGS beginning April 2018 as discussed below, primarily due to the Red Bluff Express pipeline coming online in May 2018, as well as new contracts;
|
•
|
a net increase of $11 million primarily due to the consolidation of RIGS beginning April 2018, resulting in increases in transportation fees, retained fuel revenues and operating expenses of $24 million, $2 million and $6 million, respectively, partially offset by a decrease in Adjusted EBITDA related to unconsolidated affiliates of $9 million; and
|
•
|
an increase of $7 million in realized storage margin primarily due to a realized adjustment to the Bammel storage inventory of $25 million in 2018 and higher storage fees, partially offset by a $20 million decrease due to lower physical withdrawals; partially offset by
|
•
|
a decrease of $9 million in retained fuel revenues primarily due to lower gas prices; and
|
•
|
a decrease of $5 million in realized natural gas sales and other due to lower realized gains from pipeline optimization activity.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Natural gas transported (BBtu/d)
|
11,346
|
|
|
9,542
|
|
|
1,804
|
|
|||
Natural gas sold (BBtu/d)
|
17
|
|
|
17
|
|
|
—
|
|
|||
Revenues
|
$
|
1,963
|
|
|
$
|
1,682
|
|
|
$
|
281
|
|
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
|
(569
|
)
|
|
(431
|
)
|
|
(138
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
|
(72
|
)
|
|
(63
|
)
|
|
(9
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
477
|
|
|
492
|
|
|
(15
|
)
|
|||
Other
|
(7
|
)
|
|
—
|
|
|
(7
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
1,792
|
|
|
$
|
1,680
|
|
|
$
|
112
|
|
•
|
an increase in margin of $231 million from the Rover pipeline due to higher reservation and usage resulting from additional connections and utilization of additional compression;
|
•
|
an increase of $40 million in reservation and usage fees due to improved market conditions allowing us to successfully bring new volumes to the system at improved rates, primarily on our Transwestern, Tiger and Panhandle Eastern systems; and
|
•
|
an increase of $6 million from the Sea Robin pipeline due to higher rates resulting from the rate case filed in June 2019, as well as fewer third party supply interruptions on the Sea Robin system; partially offset by
|
•
|
an increase of $138 million in operating expense primarily due to an increase in ad valorem taxes of $126 million on the Rover pipeline system resulting from placing the final portions of this asset into service in November 2018, an increase of $24 million in transportation expense on Rover due to an increase in transportation volumes, an increase of $5 million in allocated overhead costs and additional operating expense of $4 million for assets acquired in June 2019, partially offset by lower gas imbalance and system gas activity of $15 million and lower storage capacity leased on the Panhandle Eastern system of $8 million;
|
•
|
an increase of $9 million in selling, general and administrative expenses primarily due to an increase in insurance expense of $8 million, an increase in employee cost of $4 million, and an increase in allocated overhead costs of $3 million, partially offset by lower Ohio excise tax on our Rover system; and
|
•
|
a decrease of $15 million in adjusted EBITDA related to unconsolidated affiliates primarily resulting from a $20 million decrease due to lower earnings from MEP as a result of lower capacity being re-contracted at lower rates on expiring contracts, partially offset by a $5 million increase from our Citrus joint venture as we brought new volumes to the system in 2019.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Gathered volumes (BBtu/d)
|
13,431
|
|
|
12,126
|
|
|
1,305
|
|
|||
NGLs produced (MBbls/d)
|
570
|
|
|
540
|
|
|
30
|
|
|||
Equity NGLs (MBbls/d)
|
31
|
|
|
29
|
|
|
2
|
|
|||
Revenues
|
$
|
6,019
|
|
|
$
|
7,522
|
|
|
$
|
(1,503
|
)
|
Cost of products sold
|
3,570
|
|
|
5,145
|
|
|
(1,575
|
)
|
|||
Segment margin
|
2,449
|
|
|
2,377
|
|
|
72
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(789
|
)
|
|
(705
|
)
|
|
(84
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(90
|
)
|
|
(81
|
)
|
|
(9
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
27
|
|
|
33
|
|
|
(6
|
)
|
|||
Other
|
2
|
|
|
3
|
|
|
(1
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
1,599
|
|
|
$
|
1,627
|
|
|
$
|
(28
|
)
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Gathering and processing fee-based revenues
|
$
|
1,998
|
|
|
$
|
1,788
|
|
|
$
|
210
|
|
Non-fee based contracts and processing
|
451
|
|
|
589
|
|
|
(138
|
)
|
|||
Total segment margin
|
$
|
2,449
|
|
|
$
|
2,377
|
|
|
$
|
72
|
|
•
|
a decrease of $138 million in non fee-based margin due to lower NGL prices of $131 million and lower gas prices of $58 million, offset by an increase of $51 million in non fee-based margin due to increased throughput volume in North Texas, South Texas and Permian regions;
|
•
|
an increase of $84 million in operating expenses due to increases of $33 million in outside services, $29 million in maintenance project costs, $17 million in employee costs and $6 million in office expenses and materials; and
|
•
|
an increase of $9 million in selling, general and administrative expenses primarily due to a decrease of $5 million in capitalized overhead and an increase of $4 million in insurance expense; partially offset by
|
•
|
an increase of $210 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
NGL transportation volumes (MBbls/d)
|
1,289
|
|
|
1,027
|
|
|
262
|
|
|||
Refined products transportation volumes (MBbls/d)
|
583
|
|
|
621
|
|
|
(38
|
)
|
|||
NGL and refined products terminal volumes (MBbls/d)
|
944
|
|
|
812
|
|
|
132
|
|
|||
NGL fractionation volumes (MBbls/d)
|
706
|
|
|
527
|
|
|
179
|
|
|||
Revenues
|
$
|
11,641
|
|
|
$
|
11,123
|
|
|
$
|
518
|
|
Cost of products sold
|
8,393
|
|
|
8,462
|
|
|
(69
|
)
|
|||
Segment margin
|
3,248
|
|
|
2,661
|
|
|
587
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
81
|
|
|
(86
|
)
|
|
167
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(656
|
)
|
|
(604
|
)
|
|
(52
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(93
|
)
|
|
(74
|
)
|
|
(19
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
83
|
|
|
82
|
|
|
1
|
|
|||
Segment Adjusted EBITDA
|
$
|
2,663
|
|
|
$
|
1,979
|
|
|
$
|
684
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Fractionators and refinery services margin
|
$
|
664
|
|
|
$
|
511
|
|
|
$
|
153
|
|
Transportation margin
|
1,716
|
|
|
1,233
|
|
|
483
|
|
|||
Storage margin
|
223
|
|
|
211
|
|
|
12
|
|
|||
Terminal Services margin
|
630
|
|
|
494
|
|
|
136
|
|
|||
Marketing margin
|
96
|
|
|
126
|
|
|
(30
|
)
|
|||
Unrealized gains (losses) on commodity risk management activities
|
(81
|
)
|
|
86
|
|
|
(167
|
)
|
|||
Total segment margin
|
$
|
3,248
|
|
|
$
|
2,661
|
|
|
$
|
587
|
|
•
|
an increase of $483 million in transportation margin primarily due to a $265 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $212 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $29 million increase due to higher throughput volumes from the Barnett region, a $9 million increase from the Eagle Ford region, and a $9 million increase due to the
|
•
|
an increase of $153 million in fractionation and refinery services margin primarily due to a $167 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a reclassification between our fractionation and storage margins;
|
•
|
an increase of $136 million in terminal services margin primarily due to a $171 million increase from the initiation of service of our Mariner East 2 pipeline which commenced operations in the fourth quarter of 2018 and a $7 million increase due to increased tank lease revenue from third-party customers. These increases were partially offset by a $16 million decrease in volumes and expense reimbursements from third parties on Mariner East 1, a $16 million decrease due to lower volumes from third party pipeline, truck and rail deliveries into our Marcus Hook terminal, a $5 million decrease due to fewer vessels exported out of our Nederland terminal, and a $4 million decrease due to the closure of a third party refinery during the third quarter of 2019; and
|
•
|
an increase of $12 million in storage margin primarily due to a reclassification between our storage and fractionation margins; partially offset by
|
•
|
a decrease of $30 million in marketing margin primarily due to capacity lease fees incurred by our marketing affiliate on our Mariner East 2 pipeline, offset by increased gains from our butane blending business due to more favorable market conditions and increased volumes, as well as increased optimization gains from the sale of NGL component products at our Mont Belvieu facility;
|
•
|
an increase of $52 million in operating expenses primarily due to a $26 million increase in employee and ad valorem tax expenses on our terminals, fractionation, and transportation operations, a $14 million increase in utility costs to operate our pipelines and our fifth and sixth fractionators which commenced July 2018 and February 2019, respectively, and an $8 million increase in maintenance project costs due to the timing of multiple projects on our transportation assets; and
|
•
|
an increase of $19 million in general and administrative expenses primarily due to a $10 million increase in allocated overhead costs, a $5 million increase in insurance expenses, a $4 million increase in legal fees, and a $2 million increase in employee costs.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Crude transportation volumes (MBbls/d)
|
4,662
|
|
|
4,172
|
|
|
490
|
|
|||
Crude terminals volumes (MBbls/d)
|
2,068
|
|
|
2,096
|
|
|
(28
|
)
|
|||
Revenue
|
$
|
18,307
|
|
|
$
|
17,332
|
|
|
$
|
975
|
|
Cost of products sold
|
14,649
|
|
|
14,439
|
|
|
210
|
|
|||
Segment margin
|
3,658
|
|
|
2,893
|
|
|
765
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
(70
|
)
|
|
55
|
|
|
(125
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(560
|
)
|
|
(547
|
)
|
|
(13
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(84
|
)
|
|
(86
|
)
|
|
2
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
6
|
|
|
15
|
|
|
(9
|
)
|
|||
Other
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
2,949
|
|
|
$
|
2,330
|
|
|
$
|
619
|
|
•
|
an increase of $640 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $282 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region and contributions from capacity expansion projects placed into service, a $219 million increase in throughput on our Bakken pipeline, a favorable inventory valuation adjustment of
|
•
|
an increase of $13 million in operating expenses primarily due to a $30 million increase in throughput-related costs on existing assets, partially offset by a $14 million decrease in management fees as well as the impact of certain intrasegment transactions discussed above; and
|
•
|
a decrease of $9 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Revenues
|
$
|
16,596
|
|
|
$
|
16,994
|
|
|
$
|
(398
|
)
|
Cost of products sold
|
15,380
|
|
|
15,872
|
|
|
(492
|
)
|
|||
Segment margin
|
1,216
|
|
|
1,122
|
|
|
94
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
(5
|
)
|
|
6
|
|
|
(11
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(365
|
)
|
|
(435
|
)
|
|
70
|
|
|||
Selling, general and administrative, excluding non-cash compensation expense
|
(123
|
)
|
|
(129
|
)
|
|
6
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
4
|
|
|
—
|
|
|
4
|
|
|||
Inventory valuation adjustments
|
(79
|
)
|
|
85
|
|
|
(164
|
)
|
|||
Adjusted EBITDA from discontinued operations
|
—
|
|
|
(25
|
)
|
|
25
|
|
|||
Other, net
|
17
|
|
|
14
|
|
|
3
|
|
|||
Segment Adjusted EBITDA
|
$
|
665
|
|
|
$
|
638
|
|
|
$
|
27
|
|
•
|
a decrease in operating costs of $76 million, primarily as a result of the conversion of 207 retail sites to commission agent sites during April 2018. These expenses include other operating expense, general and administrative expense and lease expense; and
|
•
|
an increase of $25 million related to Adjusted EBITDA from discontinued operations related to the divestment of 1,030 company-operated fuel sites to 7-Eleven in January 2018; and
|
•
|
an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to Sunoco LP’s investment in the JC Nolan joint venture; partially offset by
|
•
|
a decrease in the gross profit on motor fuel sales of $76 million (excluding the change in inventory fair value adjustments and unrealized gains and losses on commodity risk management activities) primarily due to lower fuel margins, a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier recorded in 2018 and an $8 million one-time charge related to a reserve for an open contractual dispute recorded in 2019, partially offset by an increase in gallons sold.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Revenues
|
$
|
698
|
|
|
$
|
508
|
|
|
$
|
190
|
|
Cost of products sold
|
91
|
|
|
67
|
|
|
24
|
|
|||
Segment margin
|
607
|
|
|
441
|
|
|
166
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(134
|
)
|
|
(110
|
)
|
|
(24
|
)
|
|||
Selling, general and administrative, excluding non-cash compensation expense
|
(53
|
)
|
|
(50
|
)
|
|
(3
|
)
|
|||
Other, net
|
—
|
|
|
8
|
|
|
(8
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
420
|
|
|
$
|
289
|
|
|
$
|
131
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2019
|
|
2018
|
|
Change
|
||||||
Revenue
|
$
|
1,660
|
|
|
$
|
2,228
|
|
|
$
|
(568
|
)
|
Cost of products sold
|
1,496
|
|
|
2,006
|
|
|
(510
|
)
|
|||
Segment margin
|
164
|
|
|
222
|
|
|
(58
|
)
|
|||
Unrealized gains on commodity risk management activities
|
(4
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(62
|
)
|
|
(56
|
)
|
|
(6
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(55
|
)
|
|
(87
|
)
|
|
32
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
3
|
|
|
1
|
|
|
2
|
|
|||
Other and eliminations
|
58
|
|
|
(2
|
)
|
|
60
|
|
|||
Segment Adjusted EBITDA
|
$
|
104
|
|
|
$
|
76
|
|
|
$
|
28
|
|
•
|
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 7.4% interest in PES and no longer reflects PES as an affiliate; and
|
•
|
our investment in coal handling facilities.
|
•
|
an increase of $8 million in gains from park and loan and storage activity;
|
•
|
an increase of $11 million in optimized gains on residue gas sales;
|
•
|
an increase of $7 million from settled derivatives;
|
•
|
an increase of $15 million from a legal settlement;
|
•
|
an increase of $12 million from payments related to the PES bankruptcy;
|
•
|
an increase of $6 million from the recognition of deferred revenue related to a bankruptcy;
|
•
|
an increase of $3 million from power trading activities; and
|
•
|
a decrease of $21 million in merger and acquisition expenses; partially offset by
|
•
|
a decrease of $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;
|
•
|
a decrease of $8 million due to lower gas prices and increased power costs; and
|
•
|
a decrease of $11 million due to lower revenue from our compressor equipment business.
|
|
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
|
9,546
|
|
|
7,352
|
|
|
2,194
|
|
|||
Depreciation, depletion and amortization
|
(2,843
|
)
|
|
(2,541
|
)
|
|
(302
|
)
|
|||
Interest expense, net of interest capitalized
|
(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
|
110
|
|
|
80
|
|
|
30
|
|
|||
Total distributions received from unconsolidated affiliates
|
$
|
397
|
|
|
$
|
432
|
|
|
$
|
(35
|
)
|
(1)
|
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.
|
(2)
|
For the year ended December 31, 2017, equity in earnings of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
|
(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.
|
|
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, 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, 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, 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
|
$
|
1,788
|
|
|
$
|
1,690
|
|
|
$
|
98
|
|
Non-fee based contracts and processing (excluding unrealized gains and losses)
|
589
|
|
|
477
|
|
|
112
|
|
|||
Unrealized gains on commodity risk management activities
|
—
|
|
|
15
|
|
|
(15
|
)
|
|||
Total segment margin
|
$
|
2,377
|
|
|
$
|
2,182
|
|
|
$
|
195
|
|
•
|
an increase of $98 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 $79 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
|
$
|
511
|
|
|
$
|
415
|
|
|
$
|
96
|
|
Transportation margin
|
1,233
|
|
|
990
|
|
|
243
|
|
|||
Storage margin
|
211
|
|
|
214
|
|
|
(3
|
)
|
|||
Terminal Services margin
|
494
|
|
|
424
|
|
|
70
|
|
|||
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 $96 million primarily due to a $106 million increase resulting from the commissioning of our fifth fractionator in July 2018 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 $70 million due to a $36 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses, a $23 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 adoption of ASC 606 on January 1, 2018, increases of $24 million and $7 million to operating costs at our Marcus Hook and Nederland terminals, respectively, as a result of significantly higher volumes through both terminals in 2018, an $8 million increase to environmental reserves and a $1 million increase to overhead allocations and maintenance repairs performed on our refinery services assets; and
|
•
|
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 gains of $355 million due to more favorable basis spreads; partially offset by an unfavorable inventory valuation adjustment of $54 million for the 2018 year as compared to a favorable inventory valuation adjustment of $82 million for the 2017 year; 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 valuation 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.
|
|
Growth
|
|
Maintenance
|
||||||||||||
|
Low
|
|
High
|
|
Low
|
|
High
|
||||||||
Intrastate transportation and storage
|
$
|
20
|
|
|
$
|
30
|
|
|
$
|
40
|
|
|
$
|
45
|
|
Interstate transportation and storage (1)
|
100
|
|
|
125
|
|
|
140
|
|
|
145
|
|
||||
Midstream
|
625
|
|
|
650
|
|
|
125
|
|
|
130
|
|
||||
NGL and refined products transportation and services (1)
|
2,550
|
|
|
2,650
|
|
|
100
|
|
|
110
|
|
||||
Crude oil transportation and services
|
500
|
|
|
525
|
|
|
165
|
|
|
175
|
|
||||
All other (including eliminations)
|
25
|
|
|
50
|
|
|
75
|
|
|
80
|
|
||||
Total capital expenditures
|
$
|
3,820
|
|
|
$
|
4,030
|
|
|
$
|
645
|
|
|
$
|
685
|
|
(1)
|
Includes capital expenditures related to our proportionate ownership of the Bakken, Rover, and Bayou Bridge pipeline projects and our proportionate ownership of the Orbit Gulf Coast NGL export project.
|
|
Capital Expenditures Recorded During Period
|
||||||||||
Growth
|
|
Maintenance
|
|
Total
|
|||||||
Year Ended December 31, 2019:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
87
|
|
|
$
|
37
|
|
|
$
|
124
|
|
Interstate transportation and storage
|
239
|
|
|
136
|
|
|
375
|
|
|||
Midstream
|
669
|
|
|
157
|
|
|
826
|
|
|||
NGL and refined products transportation and services
|
2,854
|
|
|
122
|
|
|
2,976
|
|
|||
Crude oil transportation and services
|
310
|
|
|
82
|
|
|
392
|
|
|||
Investment in Sunoco LP
|
108
|
|
|
40
|
|
|
148
|
|
|||
Investment in USAC
|
170
|
|
|
30
|
|
|
200
|
|
|||
All other (including eliminations)
|
165
|
|
|
48
|
|
|
213
|
|
|||
Total capital expenditures
|
$
|
4,602
|
|
|
$
|
652
|
|
|
$
|
5,254
|
|
|
|
|
|
|
|
||||||
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 (1)
|
72
|
|
|
31
|
|
|
103
|
|
|||
Investment in USAC
|
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 (1)
|
129
|
|
|
48
|
|
|
177
|
|
|||
All other (including eliminations)
|
196
|
|
|
72
|
|
|
268
|
|
|||
Total capital expenditures
|
$
|
5,601
|
|
|
$
|
479
|
|
|
$
|
6,080
|
|
(1)
|
Amounts related to Sunoco LP’s capital expenditures include capital expenditures related to discontinued operations.
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
ETO Senior Notes
|
$
|
36,118
|
|
|
$
|
28,755
|
|
Transwestern Senior Notes
|
575
|
|
|
575
|
|
||
Panhandle Senior Notes
|
235
|
|
|
385
|
|
||
Bakken Senior Notes
|
2,500
|
|
|
—
|
|
||
Sunoco LP Senior Notes, Term Loan and lease-related obligations
|
2,935
|
|
|
2,307
|
|
||
USAC Senior Notes
|
1,475
|
|
|
725
|
|
||
Revolving credit facilities:
|
|
|
|
||||
ETO $2.00 billion Term Loan facility due October 2022
|
2,000
|
|
|
—
|
|
||
ETO $5.00 billion Revolving Credit Facility due December 2023
|
4,214
|
|
|
3,694
|
|
||
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023
|
162
|
|
|
700
|
|
||
USAC $1.60 billion Revolving Credit Facility due April 2023
|
403
|
|
|
1,050
|
|
||
Bakken $2.50 billion Credit Facility due August 2019
|
—
|
|
|
2,500
|
|
||
Other long-term debt
|
2
|
|
|
7
|
|
||
Unamortized premiums, net of discounts and fair value adjustments
|
3
|
|
|
31
|
|
||
Deferred debt issuance costs
|
(276
|
)
|
|
(221
|
)
|
||
Total debt
|
50,346
|
|
|
40,508
|
|
||
Less: current maturities of long-term debt
|
12
|
|
|
2,655
|
|
||
Long-term debt, less current maturities
|
$
|
50,334
|
|
|
$
|
37,853
|
|
•
|
$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.
|
•
|
$650 million aggregate principal amount of 3.625% senior notes due 2022;
|
•
|
$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and
|
•
|
$850 million aggregate principal amount of 4.625% senior notes due 2029.
|
•
|
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.
|
•
|
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) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0 to 1.0 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
|
|
$
|
50,619
|
|
|
$
|
3,021
|
|
|
$
|
7,204
|
|
|
$
|
13,297
|
|
|
$
|
27,097
|
|
Interest on long-term debt(1)
|
|
40,939
|
|
|
2,522
|
|
|
4,917
|
|
|
4,276
|
|
|
29,224
|
|
|||||
Payments on derivatives
|
|
401
|
|
|
150
|
|
|
251
|
|
|
—
|
|
|
—
|
|
|||||
Purchase commitments (2)
|
|
2,133
|
|
|
2,053
|
|
|
57
|
|
|
7
|
|
|
16
|
|
|||||
Transportation, natural gas storage and fractionation contracts
|
|
16
|
|
|
5
|
|
|
6
|
|
|
5
|
|
|
—
|
|
|||||
Operating lease obligations
|
|
1,548
|
|
|
98
|
|
|
166
|
|
|
140
|
|
|
1,144
|
|
|||||
Service concession arrangement(3)
|
|
379
|
|
|
15
|
|
|
30
|
|
|
32
|
|
|
302
|
|
|||||
Other(4)
|
|
190
|
|
|
25
|
|
|
48
|
|
|
40
|
|
|
77
|
|
|||||
Total(5)
|
|
$
|
96,225
|
|
|
$
|
7,889
|
|
|
$
|
12,679
|
|
|
$
|
17,797
|
|
|
$
|
57,860
|
|
(1)
|
Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2019. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2019. 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, 2019 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, AROs, 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 $3.11 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
|
|
Series E
|
|
||||||||||
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
|
|
|
—
|
|
|
|||||
March 31, 2019
|
|
May 1, 2019
|
|
May 15, 2019
|
|
—
|
|
|
—
|
|
|
0.4609
|
|
|
0.4766
|
|
|
—
|
|
|
|||||
June 30, 2019
|
|
August 1, 2019
|
|
August 15, 2019
|
|
31.2500
|
|
|
33.1250
|
|
|
0.4609
|
|
|
0.4766
|
|
|
0.5806
|
|
*
|
|||||
September 30, 2019
|
|
November 1, 2019
|
|
November 15, 2019
|
|
—
|
|
|
—
|
|
|
0.4609
|
|
|
0.4766
|
|
|
0.4750
|
|
|
|||||
December 31, 2019
|
|
February 3, 2020
|
|
February 18, 2020
|
|
31.2500
|
|
|
33.1250
|
|
|
0.4609
|
|
|
0.4766
|
|
|
0.4750
|
|
|
*
|
Represent prorated initial distributions. Prorated initial distributions on the recently issued Series F and Series G preferred units will be payable in May 2020.
|
|
|
|
|
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, 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
|
|
|
March 31, 2019
|
|
May 7, 2019
|
|
May 15, 2019
|
|
0.8255
|
|
|
June 30, 2019
|
|
August 6, 2019
|
|
August 14, 2019
|
|
0.8255
|
|
|
September 30, 2019
|
|
November 5, 2019
|
|
November 19, 2019
|
|
0.8255
|
|
|
December 31, 2019
|
|
February 7, 2020
|
|
February 19, 2020
|
|
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
|
|
|
March 31, 2019
|
|
April 29, 2019
|
|
May 10, 2019
|
|
0.5250
|
|
|
June 30, 2019
|
|
July 29, 2019
|
|
August 9, 2019
|
|
0.5250
|
|
|
September 30, 2019
|
|
October 28, 2019
|
|
November 8, 2019
|
|
0.5250
|
|
|
December 31, 2019
|
|
January 27, 2020
|
|
February 7, 2020
|
|
0.5250
|
|
•
|
A $12 million impairment was recorded related to the goodwill associated with the Partnership’s Southwest Gas operations within the interstate segment primarily due to decreases in projected future revenues and cash flows. Additionally, the Partnership recorded a $9 million impairment related to the goodwill associated with the Partnership’s North Central operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows.
|
•
|
Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York.
|
•
|
USAC also recognized a $6 million fixed asset impairment related to certain idle compressor assets.
|
•
|
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 assets were 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.
|
•
|
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.
|
•
|
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, 2019
|
|
December 31, 2018
|
||||||||||||||||||
|
Notional Volume
|
|
Fair Value Asset (Liability)
|
|
Effect of Hypothetical 10% Change
|
|
Notional Volume
|
|
Fair Value Asset (Liability)
|
|
Effect of Hypothetical 10% Change
|
||||||||||
Mark-to-Market Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Swaps/Futures
|
1,483
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
468
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Basis Swaps IFERC/NYMEX(1)
|
(35,208
|
)
|
|
2
|
|
|
5
|
|
|
16,845
|
|
|
7
|
|
|
1
|
|
||||
Options – Puts
|
—
|
|
|
—
|
|
|
—
|
|
|
10,000
|
|
|
—
|
|
|
—
|
|
||||
Power (Megawatt):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Forwards
|
3,213,450
|
|
|
6
|
|
|
8
|
|
|
3,141,520
|
|
|
6
|
|
|
8
|
|
||||
Futures
|
(353,527
|
)
|
|
1
|
|
|
2
|
|
|
56,656
|
|
|
—
|
|
|
—
|
|
||||
Options – Puts
|
51,615
|
|
|
1
|
|
|
—
|
|
|
18,400
|
|
|
—
|
|
|
—
|
|
||||
Options – Calls
|
(2,704,330
|
)
|
|
1
|
|
|
—
|
|
|
284,800
|
|
|
1
|
|
|
—
|
|
||||
Crude (MBbls) – Futures
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
(Non-Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basis Swaps IFERC/NYMEX
|
(18,923
|
)
|
|
(35
|
)
|
|
15
|
|
|
(30,228
|
)
|
|
(52
|
)
|
|
13
|
|
||||
Swing Swaps IFERC
|
(9,265
|
)
|
|
—
|
|
|
4
|
|
|
54,158
|
|
|
12
|
|
|
—
|
|
||||
Fixed Swaps/Futures
|
(3,085
|
)
|
|
(1
|
)
|
|
1
|
|
|
(1,068
|
)
|
|
19
|
|
|
1
|
|
||||
Forward Physical Contracts
|
(13,364
|
)
|
|
3
|
|
|
3
|
|
|
(123,254
|
)
|
|
(1
|
)
|
|
32
|
|
||||
NGL (MBbls) – Forwards/Swaps
|
(1,300
|
)
|
|
(18
|
)
|
|
18
|
|
|
(2,135
|
)
|
|
67
|
|
|
67
|
|
||||
Crude (MBbls) – Forwards/Swaps
|
4,465
|
|
|
13
|
|
|
2
|
|
|
20,888
|
|
|
(60
|
)
|
|
29
|
|
||||
Refined Products (MBbls) – Futures
|
(2,473
|
)
|
|
(2
|
)
|
|
16
|
|
|
(1,403
|
)
|
|
(8
|
)
|
|
6
|
|
||||
Corn (thousand bushels)
|
(1,210
|
)
|
|
—
|
|
|
—
|
|
|
(1,920
|
)
|
|
—
|
|
|
1
|
|
||||
Fair Value Hedging Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Non-Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basis Swaps IFERC/NYMEX
|
(31,780
|
)
|
|
1
|
|
|
7
|
|
|
(17,445
|
)
|
|
(4
|
)
|
|
—
|
|
||||
Fixed Swaps/Futures
|
(31,780
|
)
|
|
23
|
|
|
7
|
|
|
(17,445
|
)
|
|
(10
|
)
|
|
6
|
|
(1)
|
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
|
Term
|
|
Type(1)
|
|
Notional Amount Outstanding
|
||||||
December 31, 2019
|
|
December 31, 2018
|
||||||||
March 2019
|
|
Pay a floating rate and receive a fixed rate of 1.42%
|
|
$
|
—
|
|
|
$
|
300
|
|
July 2019 (2)
|
|
Forward-starting to pay a fixed rate of 3.56% and receive a floating rate
|
|
—
|
|
|
400
|
|
||
July 2020 (2)(3)
|
|
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
|
|
|
400
|
|
||
July 2022 (2)
|
|
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
|
|
400
|
|
|
—
|
|
(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.
|
(3)
|
The July 2020 interest rate swaps were terminated in January 2020.
|
Name
|
|
Age
|
|
|
Position with Our General Partner
|
Kelcy L. Warren
|
|
64
|
|
|
Chief Executive Officer and Chairman of the Board of Directors
|
Matthew S. Ramsey
|
|
64
|
|
|
Director, President and Chief Operating Officer
|
Thomas E. Long
|
|
63
|
|
|
Chief Financial Officer
|
Marshall S. (Mackie) McCrea, III
|
|
60
|
|
|
Director and ET President and Chief Commercial Officer
|
James M. Wright, Jr.
|
|
51
|
|
|
General Counsel
|
A. Troy Sturrock
|
|
49
|
|
|
Senior Vice President, Controller and Principal Accounting Officer
|
David K. Skidmore
|
|
64
|
|
|
Director
|
W. Brett Smith
|
|
60
|
|
|
Director
|
William P. Williams
|
|
82
|
|
|
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
|
|
• Marathon Petroleum Corporation
|
• Enterprise Products Partners, L.P.
|
|
• Kinder Morgan, Inc.
|
• Plains All American Pipeline, L.P.
|
|
• The Williams Companies, Inc.
|
• Valero Energy Corporation
|
|
• Phillips 66
|
• Enterprise Products Partners, L.P.
|
|
• Kinder Morgan, Inc.
|
• The Williams Companies, Inc.
|
|
• Plains All American Pipeline, L.P.
|
• Phillips 66
|
|
• MPLX LP
|
Name and Principal Position
|
|
Year
|
|
Salary
($)
|
|
Bonus
($)
|
|
Equity
Awards (1)
($)
|
|
Non-Equity
Incentive Plan
Compensation(2)
($)
|
|
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
|
|
All Other
Compensation(3)
($)
|
|
Total
($)
|
||||||||||||||
Kelcy L. Warren (4)
|
|
2019
|
|
$
|
6,156
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6,156
|
|
Chief Executive Officer
|
|
2018
|
|
6,138
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,138
|
|
|||||||
|
2017
|
|
5,926
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,926
|
|
||||||||
Thomas E. Long
|
|
2019
|
|
570,869
|
|
|
—
|
|
|
3,352,795
|
|
|
900,000
|
|
|
—
|
|
|
21,544
|
|
|
4,845,208
|
|
|||||||
Chief Financial Officer
|
|
2018
|
|
537,338
|
|
|
1,000,000
|
|
|
4,251,335
|
|
|
800,000
|
|
|
—
|
|
|
21,294
|
|
|
6,609,967
|
|
|||||||
|
2017
|
|
480,846
|
|
|
—
|
|
|
2,519,954
|
|
|
625,100
|
|
|
—
|
|
|
18,320
|
|
|
3,644,220
|
|
||||||||
Marshall S. (Mackie) McCrea, III
|
|
2019
|
|
1,094,260
|
|
|
—
|
|
|
8,734,720
|
|
|
1,750,817
|
|
|
—
|
|
|
21,544
|
|
|
11,601,341
|
|
|||||||
President and Chief Commercial Officer
|
|
2018
|
|
1,059,976
|
|
|
—
|
|
|
7,834,782
|
|
|
1,866,000
|
|
|
—
|
|
|
19,362
|
|
|
10,780,120
|
|
|||||||
|
2017
|
|
1,027,846
|
|
|
—
|
|
|
9,033,341
|
|
|
1,644,554
|
|
|
—
|
|
|
16,834
|
|
|
11,722,575
|
|
||||||||
Matthew S. Ramsey
|
|
2019
|
|
683,913
|
|
|
—
|
|
|
3,123,186
|
|
|
889,100
|
|
|
—
|
|
|
19,544
|
|
|
4,715,743
|
|
|||||||
Chief Operating Officer
|
|
2018
|
|
662,486
|
|
|
—
|
|
|
2,818,415
|
|
|
900,000
|
|
|
—
|
|
|
19,294
|
|
|
4,400,195
|
|
|||||||
|
2017
|
|
642,404
|
|
|
—
|
|
|
3,763,893
|
|
|
835,125
|
|
|
—
|
|
|
18,618
|
|
|
5,260,040
|
|
||||||||
Thomas P. Mason
|
|
2019
|
|
619,899
|
|
|
—
|
|
|
2,749,440
|
|
|
805,900
|
|
|
—
|
|
|
19,544
|
|
|
4,194,783
|
|
|||||||
Executive Vice President, General Counsel and President – LNG
|
|
2018
|
|
600,477
|
|
|
—
|
|
|
2,466,882
|
|
|
858,700
|
|
|
—
|
|
|
19,294
|
|
|
3,945,353
|
|
|||||||
|
2017
|
|
582,275
|
|
|
—
|
|
|
2,816,048
|
|
|
756,958
|
|
|
—
|
|
|
18,618
|
|
|
4,173,899
|
|
(1)
|
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.
|
(2)
|
ET maintains the Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis. The
|
(3)
|
The amounts reflected for 2019 in this column include (i) matching contributions to the ET 401(k) Plan made on behalf of the named executive officers of $14,000 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 2019, distribution payments in connection with distribution equivalent rights totaled $796,382 for Mr. Long, $2,178,361 for Mr. McCrea, $857,108 for Mr. Ramsey, and $756,879 for Mr. Mason.
|
(4)
|
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
(#)
|
|
Grant Date Fair Value of Unit Awards (1)
|
|||
ET Unit Awards:
|
|
|
|
|
|
|
|||
Kelcy L. Warren
|
|
N/A
|
|
—
|
|
|
$
|
—
|
|
Thomas E. Long
|
|
12/16/2019
|
|
215,000
|
|
|
2,752,000
|
|
|
Marshal S. (Mackie) McCrea, III
|
|
12/16/2019
|
|
682,400
|
|
|
8,734,720
|
|
|
Matthew S. Ramsey
|
|
12/16/2019
|
|
189,600
|
|
|
2,426,880
|
|
|
Thomas P. Mason
|
|
12/16/2019
|
|
214,800
|
|
|
2,749,440
|
|
|
Sunoco LP Unit Awards:
|
|
|
|
|
|
|
|||
Thomas E. Long
|
|
12/16/2019
|
|
19,500
|
|
|
600,795
|
|
|
Matthew S. Ramsey
|
|
12/16/2019
|
|
22,600
|
|
|
696,306
|
|
(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.
|
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
|
|
12/16/2019
|
|
215,000
|
|
|
2,758,450
|
|
|
|
|
12/18/2018
|
|
136,475
|
|
|
1,750,974
|
|
|
|
|
10/19/2018
|
|
115,200
|
|
|
1,478,016
|
|
|
|
|
12/20/2017
|
|
121,074
|
|
|
1,553,379
|
|
|
|
|
12/29/2016
|
|
30,235
|
|
|
387,918
|
|
|
|
|
12/9/2015
|
|
14,227
|
|
|
182,535
|
|
|
|
|
12/4/2015
|
|
5,739
|
|
|
73,635
|
|
|
Marshal S. (Mackie) McCrea, III
|
|
12/16/2019
|
|
682,400
|
|
|
8,755,192
|
|
|
|
|
12/18/2018
|
|
605,740
|
|
|
7,771,644
|
|
|
|
|
12/20/2017
|
|
537,379
|
|
|
6,894,573
|
|
|
|
12/29/2016
|
|
172,231
|
|
|
2,209,729
|
|
|
|
|
12/9/2015
|
|
94,855
|
|
|
1,216,987
|
|
|
|
|
12/4/2015
|
|
47,816
|
|
|
613,480
|
|
|
Matthew S. Ramsey
|
|
12/16/2019
|
|
189,600
|
|
|
2,432,568
|
|
|
|
|
12/18/2018
|
|
168,260
|
|
|
2,158,776
|
|
|
|
|
12/20/2017
|
|
223,908
|
|
|
2,872,740
|
|
|
|
|
12/29/2016
|
|
73,440
|
|
|
942,235
|
|
|
|
|
12/9/2015
|
|
59,282
|
|
|
760,592
|
|
|
Thomas P. Mason
|
|
12/16/2019
|
|
214,800
|
|
|
2,755,884
|
|
|
|
|
12/18/2018
|
|
190,640
|
|
|
2,445,911
|
|
|
|
|
12/20/2017
|
|
135,300
|
|
|
1,735,899
|
|
|
|
|
12/29/2016
|
|
40,645
|
|
|
521,474
|
|
|
|
|
12/9/2015
|
|
22,391
|
|
|
287,277
|
|
|
|
|
12/4/2015
|
|
11,287
|
|
|
144,812
|
|
|
|
|
|
|
|
|
|
|||
Sunoco LP Unit Awards:
|
|
|
|
|
|
|
|||
Thomas E. Long
|
|
12/16/2019
|
|
19,500
|
|
|
$
|
596,700
|
|
|
|
12/19/2018
|
|
19,325
|
|
|
591,345
|
|
|
|
|
12/21/2017
|
|
17,097
|
|
|
523,168
|
|
|
|
|
12/29/2016
|
|
8,884
|
|
|
271,850
|
|
|
|
|
12/16/2015
|
|
5,650
|
|
|
172,890
|
|
|
Matthew S. Ramsey
|
|
12/16/2019
|
|
22,600
|
|
|
691,560
|
|
|
|
|
12/19/2018
|
|
23,825
|
|
|
729,045
|
|
|
|
|
1/2/2015
|
|
814
|
|
|
24,908
|
|
|
Thomas P. Mason
|
|
12/21/2017
|
|
19,106
|
|
|
584,644
|
|
|
|
|
12/29/2016
|
|
9,320
|
|
|
285,192
|
|
|
|
|
12/16/2015
|
|
7,410
|
|
|
226,752
|
|
(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 2022 and 40% in December 2024 for awards granted in December 2019. 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;
|
•
|
100% in December 2021 for the remaining outstanding portion of awards granted in December 2016; and
|
•
|
100% in December 2020 for the remaining outstanding portion of awards granted in December 2015.
|
(3)
|
Market value was computed as the number of unvested awards as of December 31, 2019 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
|
|
N/A
|
|
|
$
|
—
|
|
Thomas E. Long
|
|
55,839
|
|
|
647,730
|
|
|
Marshall S. (Mackie) McCrea, III
|
|
327,520
|
|
|
3,799,236
|
|
|
Matthew S. Ramsey
|
|
110,161
|
|
|
1,277,868
|
|
|
Thomas P. Mason
|
|
85,300
|
|
|
989,482
|
|
|
Sunoco LP Unit Awards:
|
|
|
|
|
|||
Thomas E. Long
|
|
13,326
|
|
|
401,779
|
|
|
Matthew S. Ramsey
|
|
299
|
|
|
9,033
|
|
|
Thomas P. Mason
|
|
13,980
|
|
|
421,497
|
|
(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, 2019, the applicable employee populations consisted of 8,256 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 2018 or 2019 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 2019, updated with compensation of the “median employee” as reflected in our payroll records as reported on Form W-2 for 2019.
|
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 2019 resulting in an annual compensation of $124,622. 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 $10,989) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $6,040 per employee, includes $3,775 per employee on average matching contribution and $2,265 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).
|
5.
|
With respect to Mr. Warren, we used the amount reported in the “Total” column of our 2019 Summary Compensation Table under this Item 11.
|
Name
|
|
Fees Paid in Cash(1)
($)
|
|
Unit Awards(2)
($)
|
|
All Other Compensation
($)
|
|
Total
($)
|
||||
David K. Skidmore
|
|
125,000
|
|
|
99,998
|
|
|
—
|
|
|
224,998
|
|
W. Brett Smith
|
|
115,000
|
|
|
99,998
|
|
|
—
|
|
|
214,998
|
|
William P. Williams
|
|
115,000
|
|
|
99,998
|
|
|
—
|
|
|
214,998
|
|
(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.
|
|
Years Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
Audit fees(1)
|
$
|
10.8
|
|
|
$
|
11.1
|
|
Audit related fees
|
0.1
|
|
|
0.5
|
|
||
Tax fees(2)
|
—
|
|
|
0.1
|
|
||
Total
|
$
|
10.9
|
|
|
$
|
11.7
|
|
(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 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
|
|
|
3.8.2
|
|
|
3.8.3
|
|
|
4.1
|
|
|
4.2
|
|
|
4.3
|
|
|
4.4
|
|
|
4.5
|
|
|
4.6
|
|
|
4.7
|
|
|
4.8
|
|
|
4.9
|
|
Exhibit Number
|
|
Description
|
4.10
|
|
|
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
|
|
Exhibit Number
|
|
Description
|
4.29
|
|
|
4.30
|
|
|
4.31*
|
|
|
4.32*
|
|
|
4.33*
|
|
|
4.34*
|
|
|
10.1+
|
|
|
10.2+
|
|
|
10.3+
|
|
|
10.3.1+
|
|
|
10.4
|
|
|
10.5
|
|
|
10.6
|
|
|
10.7
|
|
|
10.8
|
|
|
10.8.1
|
|
|
10.9
|
|
|
10.10
|
|
|
10.11
|
|
|
10.11.1
|
|
Exhibit Number
|
|
Description
|
10.11.2
|
|
|
10.12
|
|
|
10.13
|
|
|
10.14
|
|
|
10.15
|
|
|
10.16
|
|
|
10.17
|
|
|
10.18
|
|
|
10.19
|
|
|
10.20
|
|
|
10.21
|
|
|
10.22
|
|
|
10.23+
|
|
|
10.24
|
|
|
10.25
|
|
|
10.26
|
|
|
10.27
|
|
|
10.28
|
|
Exhibit Number
|
|
Description
|
10.29
|
|
|
10.30
|
|
|
10.31
|
|
|
10.32
|
|
|
10.33
|
|
|
10.34
|
|
|
10.35
|
|
|
10.36
|
|
|
10.37
|
|
|
10.38
|
|
|
10.39
|
|
|
10.40
|
|
|
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, 2019 and December 31, 2018; (ii) our Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017; (iii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017; (iv) our Consolidated Statement of Partners’ Capital for the years ended December 31, 2019, 2018 and 2017; (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017; and (vi) the notes to our Consolidated Financial Statements.
|
104
|
|
Cover Page Interactive Data File (embedded within the Inline XBRL document)
|
*
|
|
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 21, 2020
|
Kelcy L. Warren
|
|
of Directors (Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Thomas E. Long
|
|
Chief Financial Officer
|
|
February 21, 2020
|
Thomas E. Long
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ A. Troy Sturrock
|
|
Senior Vice President and Controller
|
|
February 21, 2020
|
A. Troy Sturrock
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Matthew S. Ramsey
|
|
President, Chief Operating Officer and Director
|
|
February 21, 2020
|
Matthew S. Ramsey
|
|
|
|
|
|
|
|
|
|
/s/ Marshall S. McCrea, III
|
|
Chief Commercial Officer and Director
|
|
February 21, 2020
|
Marshall S. McCrea, III
|
|
|
|
|
|
|
|
|
|
/s/ David K. Skidmore
|
|
Director
|
|
February 21, 2020
|
David K. Skidmore
|
|
|
|
|
|
|
|
|
|
/s/ W. Brett Smith
|
|
Director
|
|
February 21, 2020
|
W. Brett Smith
|
|
|
|
|
|
|
|
|
|
/s/ William P. Williams
|
|
Director
|
|
February 21, 2020
|
William P. Williams
|
|
|
|
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
•
|
Compared the actual current results of the relevant reporting unit to the expected performance of that reporting unit based on prior period financial forecasts, as applicable.
|
•
|
Utilized an internal valuation specialist to evaluate:
|
◦
|
The methodologies used and whether they were acceptable for the underlying assets or operations and being applied correctly by performing independent calculations,
|
◦
|
The appropriateness of the discount rates by recalculating the weighted average costs of capital, and
|
◦
|
The qualifications of the third party valuation specialists engaged by the Partnership based on their credentials and experience.
|
•
|
Tested the reasonableness of the projected growth rate and forecasted costs by comparing such items to historical operating results of the relevant reporting unit and by assessing the likelihood or capability of the reporting unit to undertake activities or initiatives underpinning significant drivers of growth in the forecasted period.
|
•
|
Utilized an external actuarial specialist to evaluate:
|
◦
|
The methodologies used and whether they were acceptable for the underlying operations,
|
◦
|
The qualifications of the third party actuary specialist engaged by the Partnership based on their credentials and experience.
|
•
|
Evaluated the appropriateness of the discount rate used by comparing it to the historical rate of return from the captive insurance company’s investment portfolio used to fund the underlying liabilities, and
|
•
|
Evaluated the life-to-date payments, reserves, and payment patterns by agreeing the historical claims and payment amounts to the underlying claims or general ledger.
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
253
|
|
|
$
|
418
|
|
Accounts receivable, net
|
4,439
|
|
|
4,009
|
|
||
Accounts receivable from related companies
|
175
|
|
|
176
|
|
||
Inventories
|
1,847
|
|
|
1,677
|
|
||
Income taxes receivable
|
141
|
|
|
73
|
|
||
Derivative assets
|
23
|
|
|
111
|
|
||
Other current assets
|
282
|
|
|
356
|
|
||
Total current assets
|
7,160
|
|
|
6,820
|
|
||
|
|
|
|
||||
Property, plant and equipment
|
85,359
|
|
|
79,280
|
|
||
Accumulated depreciation and depletion
|
(15,388
|
)
|
|
(12,625
|
)
|
||
|
69,971
|
|
|
66,655
|
|
||
|
|
|
|
||||
Advances to and investments in unconsolidated affiliates
|
3,018
|
|
|
2,636
|
|
||
Lease right-of-use assets, net
|
877
|
|
|
—
|
|
||
Other non-current assets, net
|
976
|
|
|
1,006
|
|
||
Long-term affiliate receivable
|
5,926
|
|
|
440
|
|
||
Intangible assets, net
|
5,695
|
|
|
6,000
|
|
||
Goodwill
|
4,902
|
|
|
4,885
|
|
||
Total assets
|
$
|
98,525
|
|
|
$
|
88,442
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
3,625
|
|
|
$
|
3,491
|
|
Accounts payable to related companies
|
27
|
|
|
119
|
|
||
Derivative liabilities
|
147
|
|
|
185
|
|
||
Operating lease current liabilities
|
54
|
|
|
—
|
|
||
Accrued and other current liabilities
|
3,216
|
|
|
2,847
|
|
||
Current maturities of long-term debt
|
12
|
|
|
2,655
|
|
||
Total current liabilities
|
7,081
|
|
|
9,297
|
|
||
|
|
|
|
||||
Long-term debt, less current maturities
|
50,334
|
|
|
37,853
|
|
||
Non-current derivative liabilities
|
273
|
|
|
104
|
|
||
Non-current operating lease liabilities
|
816
|
|
|
—
|
|
||
Deferred income taxes
|
3,113
|
|
|
2,884
|
|
||
Other non-current liabilities
|
1,109
|
|
|
1,184
|
|
||
|
|
|
|
||||
Commitments and contingencies
|
|
|
|
||||
Redeemable noncontrolling interests
|
492
|
|
|
499
|
|
||
|
|
|
|
||||
Equity:
|
|
|
|
||||
Limited Partners:
|
|
|
|
||||
Series A Preferred Unitholders (950,000 units authorized, issued and outstanding as of December 31, 2019 and 2018, respectively)
|
958
|
|
|
958
|
|
||
Series B Preferred Unitholders (550,000 units authorized, issued and outstanding as of December 31, 2019 and 2018, respectively)
|
556
|
|
|
556
|
|
||
Series C Preferred Unitholders (18,000,000 units authorized, issued and outstanding as of December 31, 2019 and 2018, respectively)
|
440
|
|
|
440
|
|
||
Series D Preferred Unitholders (17,800,000 units authorized, issued and outstanding as of December 31, 2019 and 2018, respectively)
|
434
|
|
|
434
|
|
||
Series E Preferred Unitholders (32,000,000 units authorized, issued and outstanding as of December 31, 2019)
|
786
|
|
|
—
|
|
||
Common Unitholders and Other
|
24,133
|
|
|
26,372
|
|
||
Accumulated other comprehensive loss
|
(18
|
)
|
|
(42
|
)
|
||
Total partners’ capital
|
27,289
|
|
|
28,718
|
|
||
Noncontrolling interests
|
8,018
|
|
|
7,903
|
|
||
Total equity
|
35,307
|
|
|
36,621
|
|
||
Total liabilities and equity
|
$
|
98,525
|
|
|
$
|
88,442
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
REVENUES:
|
|
|
|
|
|
||||||
Refined product sales
|
$
|
16,634
|
|
|
$
|
17,458
|
|
|
$
|
11,166
|
|
Crude sales
|
15,917
|
|
|
14,425
|
|
|
10,706
|
|
|||
NGL sales
|
8,290
|
|
|
9,986
|
|
|
7,781
|
|
|||
Gathering, transportation and other fees
|
9,042
|
|
|
6,797
|
|
|
4,435
|
|
|||
Natural gas sales
|
3,295
|
|
|
4,452
|
|
|
4,172
|
|
|||
Other
|
854
|
|
|
969
|
|
|
2,263
|
|
|||
Total revenues
|
54,032
|
|
|
54,087
|
|
|
40,523
|
|
|||
COSTS AND EXPENSES:
|
|
|
|
|
|
||||||
Cost of products sold
|
39,603
|
|
|
41,658
|
|
|
30,966
|
|
|||
Operating expenses
|
3,267
|
|
|
3,089
|
|
|
2,644
|
|
|||
Depreciation, depletion and amortization
|
3,124
|
|
|
2,843
|
|
|
2,541
|
|
|||
Selling, general and administrative
|
679
|
|
|
664
|
|
|
568
|
|
|||
Impairment losses
|
74
|
|
|
431
|
|
|
1,039
|
|
|||
Total costs and expenses
|
46,747
|
|
|
48,685
|
|
|
37,758
|
|
|||
OPERATING INCOME
|
7,285
|
|
|
5,402
|
|
|
2,765
|
|
|||
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
||||||
Interest expense, net of interest capitalized
|
(2,257
|
)
|
|
(1,709
|
)
|
|
(1,575
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
298
|
|
|
344
|
|
|
144
|
|
|||
Impairment of investments in unconsolidated affiliates
|
—
|
|
|
—
|
|
|
(313
|
)
|
|||
Losses on extinguishments of debt
|
(2
|
)
|
|
(109
|
)
|
|
(42
|
)
|
|||
Gains (losses) on interest rate derivatives
|
(241
|
)
|
|
47
|
|
|
(37
|
)
|
|||
Other, net
|
303
|
|
|
69
|
|
|
206
|
|
|||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)
|
5,386
|
|
|
4,044
|
|
|
1,148
|
|
|||
Income tax expense (benefit) from continuing operations
|
200
|
|
|
5
|
|
|
(1,804
|
)
|
|||
INCOME FROM CONTINUING OPERATIONS
|
5,186
|
|
|
4,039
|
|
|
2,952
|
|
|||
Loss from discontinued operations, net of income taxes
|
—
|
|
|
(265
|
)
|
|
(177
|
)
|
|||
NET INCOME
|
5,186
|
|
|
3,774
|
|
|
2,775
|
|
|||
Less: Net income attributable to noncontrolling interests
|
1,051
|
|
|
715
|
|
|
420
|
|
|||
Less: Net income attributable to redeemable noncontrolling interests
|
51
|
|
|
39
|
|
|
—
|
|
|||
Less: Net income (loss) attributable to predecessor
|
—
|
|
|
(5
|
)
|
|
274
|
|
|||
NET INCOME ATTRIBUTABLE TO PARTNERS
|
$
|
4,084
|
|
|
$
|
3,025
|
|
|
$
|
2,081
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Net income
|
$
|
5,186
|
|
|
$
|
3,774
|
|
|
$
|
2,775
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
||||||
Change in value of available-for-sale securities
|
11
|
|
|
(4
|
)
|
|
6
|
|
|||
Actuarial gain (loss) relating to pension and other postretirement benefits
|
23
|
|
|
(43
|
)
|
|
(12
|
)
|
|||
Change in other comprehensive income from unconsolidated affiliates
|
(10
|
)
|
|
4
|
|
|
1
|
|
|||
|
24
|
|
|
(43
|
)
|
|
(5
|
)
|
|||
Comprehensive income
|
5,210
|
|
|
3,731
|
|
|
2,770
|
|
|||
Less: Comprehensive income attributable to noncontrolling interests
|
1,051
|
|
|
715
|
|
|
420
|
|
|||
Less: Comprehensive income attributable to redeemable noncontrolling interests
|
51
|
|
|
39
|
|
|
—
|
|
|||
Less: Comprehensive income (loss) attributable to predecessor
|
—
|
|
|
(5
|
)
|
|
274
|
|
|||
Comprehensive income attributable to partners
|
$
|
4,108
|
|
|
$
|
2,982
|
|
|
$
|
2,076
|
|
|
Limited Partners
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
|
Preferred Unitholders
|
|
Common Unitholders and Other
|
|
General
Partner |
|
AOCI
|
|
Non-controlling
Interest
|
|
Predecessor Equity
|
|
Total
|
||||||||||||||
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 interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(430
|
)
|
|
(284
|
)
|
|
(714
|
)
|
|||||||
Partnership units issued for cash
|
1,479
|
|
|
2,283
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,762
|
|
|||||||
Subsidiary units issued for cash
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
333
|
|
|
333
|
|
|||||||
Sunoco Logistics Merger
|
—
|
|
|
5,938
|
|
|
—
|
|
|
—
|
|
|
(5,938
|
)
|
|
—
|
|
|
—
|
|
|||||||
Capital contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
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
|
12
|
|
|
1,079
|
|
|
990
|
|
|
—
|
|
|
420
|
|
|
274
|
|
|
2,775
|
|
|||||||
Balance, December 31, 2017
|
1,491
|
|
|
26,531
|
|
|
244
|
|
|
3
|
|
|
5,882
|
|
|
2,816
|
|
|
36,967
|
|
|||||||
Distributions to partners
|
(100
|
)
|
|
(3,376
|
)
|
|
(1,080
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,556
|
)
|
|||||||
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(891
|
)
|
|
(276
|
)
|
|
(1,167
|
)
|
|||||||
Partnership units issued for cash
|
867
|
|
|
58
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
925
|
|
|||||||
Subsidiary units repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(300
|
)
|
|
(300
|
)
|
|||||||
Energy Transfer Merger
|
—
|
|
|
1,370
|
|
|
(340
|
)
|
|
—
|
|
|
1,474
|
|
|
(2,504
|
)
|
|
—
|
|
|||||||
Capital contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
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
|
(3
|
)
|
|
53
|
|
|
(17
|
)
|
|
(2
|
)
|
|
16
|
|
|
(12
|
)
|
|
35
|
|
|||||||
Net income (loss), excluding amounts attributable to redeemable noncontrolling interests
|
133
|
|
|
1,699
|
|
|
1,193
|
|
|
—
|
|
|
715
|
|
|
(5
|
)
|
|
3,735
|
|
|||||||
Balance, December 31, 2018
|
2,388
|
|
|
26,372
|
|
|
—
|
|
|
(42
|
)
|
|
7,903
|
|
|
—
|
|
|
36,621
|
|
|||||||
Distributions to partners
|
(197
|
)
|
|
(6,087
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,284
|
)
|
|||||||
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,399
|
)
|
|
—
|
|
|
(1,399
|
)
|
|||||||
Partnership units issued for cash
|
780
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
780
|
|
|||||||
Capital contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
348
|
|
|
—
|
|
|
348
|
|
|||||||
Sale of noncontrolling interest in subsidiary
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
93
|
|
|
—
|
|
|
93
|
|
|||||||
Other comprehensive loss, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
24
|
|
|||||||
Other, net
|
(1
|
)
|
|
(32
|
)
|
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
(11
|
)
|
|||||||
Net income, excluding amounts attributable to redeemable noncontrolling interests
|
204
|
|
|
3,880
|
|
|
—
|
|
|
—
|
|
|
1,051
|
|
|
—
|
|
|
5,135
|
|
|||||||
Balance, December 31, 2019
|
$
|
3,174
|
|
|
$
|
24,133
|
|
|
$
|
—
|
|
|
$
|
(18
|
)
|
|
$
|
8,018
|
|
|
$
|
—
|
|
|
$
|
35,307
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
OPERATING ACTIVITIES:
|
|
|
|
|
|
||||||
Net income
|
$
|
5,186
|
|
|
$
|
3,774
|
|
|
$
|
2,775
|
|
Reconciliation of net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Loss from discontinued operations
|
—
|
|
|
265
|
|
|
177
|
|
|||
Depreciation, depletion and amortization
|
3,124
|
|
|
2,843
|
|
|
2,541
|
|
|||
Deferred income taxes
|
221
|
|
|
(8
|
)
|
|
(1,841
|
)
|
|||
Inventory valuation adjustments
|
(79
|
)
|
|
85
|
|
|
(24
|
)
|
|||
Non-cash compensation expense
|
111
|
|
|
105
|
|
|
99
|
|
|||
Impairment losses
|
74
|
|
|
431
|
|
|
1,039
|
|
|||
Impairment of investments in unconsolidated affiliates
|
—
|
|
|
—
|
|
|
313
|
|
|||
Losses on extinguishment of debt
|
2
|
|
|
109
|
|
|
42
|
|
|||
Distributions on unvested awards
|
(9
|
)
|
|
(33
|
)
|
|
(35
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
(298
|
)
|
|
(344
|
)
|
|
(144
|
)
|
|||
Distributions from unconsolidated affiliates
|
285
|
|
|
328
|
|
|
297
|
|
|||
Other non-cash
|
113
|
|
|
(113
|
)
|
|
(249
|
)
|
|||
Net change in operating assets and liabilities, net of effects of acquisitions
|
(479
|
)
|
|
117
|
|
|
(173
|
)
|
|||
Net cash provided by operating activities
|
8,251
|
|
|
7,559
|
|
|
4,817
|
|
|||
INVESTING ACTIVITIES:
|
|
|
|
|
|
||||||
Cash proceeds from sale of noncontrolling interest in subsidiary
|
93
|
|
|
—
|
|
|
—
|
|
|||
Cash proceeds from USAC acquisition, net of cash received
|
—
|
|
|
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 all other acquisitions
|
(7
|
)
|
|
(429
|
)
|
|
(303
|
)
|
|||
Capital expenditures, excluding allowance for equity funds used during construction
|
(5,936
|
)
|
|
(7,407
|
)
|
|
(8,444
|
)
|
|||
Contributions in aid of construction costs
|
80
|
|
|
109
|
|
|
24
|
|
|||
Contributions to unconsolidated affiliates
|
(523
|
)
|
|
(26
|
)
|
|
(268
|
)
|
|||
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
98
|
|
|
69
|
|
|
135
|
|
|||
Proceeds from the sale of assets
|
54
|
|
|
87
|
|
|
45
|
|
|||
Other
|
18
|
|
|
(16
|
)
|
|
1
|
|
|||
Net cash used in investing activities
|
(6,123
|
)
|
|
(6,902
|
)
|
|
(5,612
|
)
|
|||
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
||||||
Proceeds from borrowings
|
22,583
|
|
|
28,538
|
|
|
29,389
|
|
|||
Repayments of debt
|
(16,874
|
)
|
|
(27,297
|
)
|
|
(29,387
|
)
|
|||
Repayments of notes payable to related party
|
(1,328
|
)
|
|
(440
|
)
|
|
(423
|
)
|
|||
Common units issued for cash
|
—
|
|
|
58
|
|
|
2,283
|
|
|||
Preferred units issued for cash
|
780
|
|
|
867
|
|
|
1,479
|
|
|||
Redeemable noncontrolling interests issued for cash
|
—
|
|
|
465
|
|
|
—
|
|
|||
Predecessor units issued for cash
|
—
|
|
|
—
|
|
|
333
|
|
|||
Capital contributions from noncontrolling interests
|
348
|
|
|
649
|
|
|
1,214
|
|
|||
Distributions to partners
|
(6,284
|
)
|
|
(4,556
|
)
|
|
(3,468
|
)
|
|||
Predecessor distributions to partners
|
—
|
|
|
(276
|
)
|
|
(284
|
)
|
|||
Distributions to noncontrolling interests
|
(1,399
|
)
|
|
(891
|
)
|
|
(430
|
)
|
|||
Distributions to redeemable noncontrolling interests
|
—
|
|
|
(24
|
)
|
|
—
|
|
|||
Repurchases of common units
|
—
|
|
|
(24
|
)
|
|
—
|
|
|||
Subsidiary repurchases of common units
|
—
|
|
|
(300
|
)
|
|
—
|
|
|||
Redemption of Legacy ETP Preferred Units
|
—
|
|
|
—
|
|
|
(53
|
)
|
|||
Debt issuance costs
|
(117
|
)
|
|
(162
|
)
|
|
(83
|
)
|
|||
Other
|
(2
|
)
|
|
85
|
|
|
2
|
|
|||
Net cash provided by (used in) financing activities
|
(2,293
|
)
|
|
(3,308
|
)
|
|
572
|
|
|||
DISCONTINUED OPERATIONS:
|
|
|
|
|
|
||||||
Operating activities
|
—
|
|
|
(484
|
)
|
|
136
|
|
|||
Investing activities
|
—
|
|
|
3,207
|
|
|
(38
|
)
|
|||
Changes in cash included in current assets held for sale
|
—
|
|
|
11
|
|
|
(5
|
)
|
|||
Net increase in cash and cash equivalents of discontinued operations
|
—
|
|
|
2,734
|
|
|
93
|
|
|||
Increase (decrease) in cash and cash equivalents
|
(165
|
)
|
|
83
|
|
|
(130
|
)
|
|||
Cash and cash equivalents, beginning of period
|
418
|
|
|
335
|
|
|
465
|
|
|||
Cash and cash equivalents, end of period
|
$
|
253
|
|
|
$
|
418
|
|
|
$
|
335
|
|
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, 2018, as previously reported
|
|
Adjustments due to Topic 842 (Leases)
|
|
Balance at January 1, 2019
|
||||||
Assets:
|
|
|
|
|
|
||||||
Property, plant and equipment, net
|
$
|
66,655
|
|
|
$
|
(1
|
)
|
|
$
|
66,654
|
|
Lease right-of-use assets, net
|
—
|
|
|
889
|
|
|
889
|
|
|||
Liabilities:
|
|
|
|
|
|
||||||
Operating lease current liabilities
|
$
|
—
|
|
|
$
|
71
|
|
|
$
|
71
|
|
Accrued and other current liabilities
|
2,847
|
|
|
(1
|
)
|
|
2,846
|
|
|||
Current maturities of long-term debt
|
2,655
|
|
|
1
|
|
|
2,656
|
|
|||
Long-term debt, less current maturities
|
37,853
|
|
|
6
|
|
|
37,859
|
|
|||
Non-current operating lease liabilities
|
—
|
|
|
823
|
|
|
823
|
|
|||
Other non-current liabilities
|
1,184
|
|
|
(12
|
)
|
|
1,172
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Accounts receivable
|
$
|
(423
|
)
|
|
$
|
506
|
|
|
$
|
(951
|
)
|
Accounts receivable from related companies
|
(25
|
)
|
|
128
|
|
|
(462
|
)
|
|||
Inventories
|
(98
|
)
|
|
282
|
|
|
58
|
|
|||
Other current assets
|
100
|
|
|
7
|
|
|
40
|
|
|||
Other non-current assets, net
|
(126
|
)
|
|
(109
|
)
|
|
(88
|
)
|
|||
Accounts payable
|
101
|
|
|
(769
|
)
|
|
713
|
|
|||
Accounts payable to related companies
|
(94
|
)
|
|
(206
|
)
|
|
486
|
|
|||
Accrued and other current liabilities
|
50
|
|
|
365
|
|
|
(56
|
)
|
|||
Other non-current liabilities
|
(183
|
)
|
|
(34
|
)
|
|
78
|
|
|||
Price risk management assets and liabilities, net
|
219
|
|
|
(53
|
)
|
|
9
|
|
|||
Net change in operating assets and liabilities, net of effects of acquisitions
|
$
|
(479
|
)
|
|
$
|
117
|
|
|
$
|
(173
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
NON-CASH INVESTING ACTIVITIES:
|
|
|
|
|
|
||||||
Accrued capital expenditures
|
$
|
1,265
|
|
|
$
|
1,030
|
|
|
$
|
1,060
|
|
Lease assets obtained in exchange for new lease liabilities
|
67
|
|
|
—
|
|
|
—
|
|
|||
Net gains (losses) from subsidiary common unit transactions
|
—
|
|
|
(127
|
)
|
|
5
|
|
|||
NON-CASH FINANCING ACTIVITIES:
|
|
|
|
|
|
||||||
Contribution of assets from noncontrolling interests
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
988
|
|
SUPPLEMENTAL CASH FLOW INFORMATION:
|
|
|
|
|
|
||||||
Cash paid for interest, net of interest capitalized
|
$
|
1,798
|
|
|
$
|
1,537
|
|
|
$
|
1,516
|
|
Cash paid for income taxes
|
30
|
|
|
508
|
|
|
50
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Natural gas, NGLs and refined products (1)
|
$
|
833
|
|
|
$
|
833
|
|
Crude oil
|
566
|
|
|
506
|
|
||
Spare parts and other
|
448
|
|
|
338
|
|
||
Total inventories
|
$
|
1,847
|
|
|
$
|
1,677
|
|
(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,
|
||||||
|
2019
|
|
2018
|
||||
Deposits paid to vendors
|
$
|
95
|
|
|
$
|
141
|
|
Prepaid expenses and other
|
187
|
|
|
215
|
|
||
Total other current assets
|
$
|
282
|
|
|
$
|
356
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Land and improvements
|
$
|
1,075
|
|
|
$
|
1,168
|
|
Buildings and improvements (1 to 45 years)
|
2,581
|
|
|
2,636
|
|
||
Pipelines and equipment (5 to 83 years)
|
62,508
|
|
|
58,783
|
|
||
Product storage and related facilities and equipment (2 to 83 years)
|
4,739
|
|
|
4,978
|
|
||
Right of way (20 to 83 years)
|
4,736
|
|
|
4,533
|
|
||
Other (1 to 48 years)
|
1,499
|
|
|
1,115
|
|
||
Construction work-in-process
|
8,221
|
|
|
6,067
|
|
||
Property, plant and equipment, gross
|
85,359
|
|
|
79,280
|
|
||
Less: Accumulated depreciation and depletion
|
(15,388
|
)
|
|
(12,625
|
)
|
||
Property, plant and equipment, net
|
$
|
69,971
|
|
|
$
|
66,655
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Depreciation, depletion and amortization expense
|
$
|
2,816
|
|
|
$
|
2,522
|
|
|
$
|
2,199
|
|
Capitalized interest
|
166
|
|
|
294
|
|
|
286
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Regulatory assets
|
$
|
42
|
|
|
$
|
43
|
|
Pension assets
|
84
|
|
|
68
|
|
||
Deferred charges
|
178
|
|
|
178
|
|
||
Restricted funds
|
178
|
|
|
178
|
|
||
Other
|
494
|
|
|
539
|
|
||
Total other non-current assets, net
|
$
|
976
|
|
|
$
|
1,006
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||
|
Gross Carrying
Amount
|
|
Accumulated
Amortization
|
|
Gross Carrying
Amount
|
|
Accumulated
Amortization
|
||||||||
Amortizable intangible assets:
|
|
|
|
|
|
|
|
||||||||
Customer relationships, contracts and agreements (3 to 46 years)
|
$
|
7,074
|
|
|
$
|
(1,741
|
)
|
|
$
|
7,106
|
|
|
$
|
(1,493
|
)
|
Patents (10 years)
|
48
|
|
|
(35
|
)
|
|
48
|
|
|
(30
|
)
|
||||
Trade Names (20 years)
|
66
|
|
|
(31
|
)
|
|
66
|
|
|
(28
|
)
|
||||
Other (5 to 20 years)
|
19
|
|
|
(12
|
)
|
|
33
|
|
|
(9
|
)
|
||||
Total amortizable intangible assets
|
7,207
|
|
|
(1,819
|
)
|
|
7,253
|
|
|
(1,560
|
)
|
||||
Non-amortizable intangible assets:
|
|
|
|
|
|
|
|
||||||||
Trademarks
|
295
|
|
|
—
|
|
|
295
|
|
|
—
|
|
||||
Other
|
12
|
|
|
—
|
|
|
12
|
|
|
—
|
|
||||
Total non-amortizable intangible assets
|
307
|
|
|
—
|
|
|
307
|
|
|
—
|
|
||||
Total intangible assets
|
$
|
7,514
|
|
|
$
|
(1,819
|
)
|
|
$
|
7,560
|
|
|
$
|
(1,560
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Reported in depreciation, depletion and amortization expense
|
$
|
308
|
|
|
$
|
321
|
|
|
$
|
336
|
|
|
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, 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
|
|
|||||||||
Acquired
|
—
|
|
|
42
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
42
|
|
|||||||||
Impaired
|
—
|
|
|
(12
|
)
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|||||||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||||||||
Balance, December 31, 2019
|
$
|
10
|
|
|
$
|
226
|
|
|
$
|
483
|
|
|
$
|
693
|
|
|
$
|
1,167
|
|
|
$
|
1,555
|
|
|
$
|
619
|
|
|
$
|
149
|
|
|
$
|
4,902
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Interest payable
|
$
|
576
|
|
|
$
|
503
|
|
Customer advances and deposits
|
123
|
|
|
128
|
|
||
Accrued capital expenditures
|
1,265
|
|
|
1,030
|
|
||
Accrued wages and benefits
|
217
|
|
|
283
|
|
||
Taxes payable other than income taxes
|
263
|
|
|
256
|
|
||
Exchanges payable
|
67
|
|
|
112
|
|
||
Other
|
705
|
|
|
535
|
|
||
Total accrued and other current liabilities
|
$
|
3,216
|
|
|
$
|
2,847
|
|
|
Fair Value Total
|
|
Fair Value Measurements at December 31, 2019
|
||||||||
|
Level 1
|
|
Level 2
|
||||||||
Assets:
|
|
|
|
|
|
||||||
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
$
|
17
|
|
|
$
|
17
|
|
|
$
|
—
|
|
Swing Swaps IFERC
|
1
|
|
|
—
|
|
|
1
|
|
|||
Fixed Swaps/Futures
|
65
|
|
|
65
|
|
|
—
|
|
|||
Forward Physical Contracts
|
3
|
|
|
—
|
|
|
3
|
|
|||
Power:
|
|
|
|
|
|
||||||
Forwards
|
11
|
|
|
—
|
|
|
11
|
|
|||
Futures
|
4
|
|
|
4
|
|
|
—
|
|
|||
Options – Puts
|
1
|
|
|
1
|
|
|
—
|
|
|||
Options – Calls
|
1
|
|
|
1
|
|
|
—
|
|
|||
NGLs – Forwards/Swaps
|
260
|
|
|
260
|
|
|
—
|
|
|||
Refined Products – Futures
|
8
|
|
|
8
|
|
|
—
|
|
|||
Crude – Forwards/Swaps
|
13
|
|
|
13
|
|
|
—
|
|
|||
Total commodity derivatives
|
384
|
|
|
369
|
|
|
15
|
|
|||
Other non-current assets
|
31
|
|
|
20
|
|
|
11
|
|
|||
Total assets
|
$
|
415
|
|
|
$
|
389
|
|
|
$
|
26
|
|
Liabilities:
|
|
|
|
|
|
||||||
Interest rate derivatives
|
$
|
(399
|
)
|
|
$
|
—
|
|
|
$
|
(399
|
)
|
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
(49
|
)
|
|
(49
|
)
|
|
—
|
|
|||
Swing Swaps IFERC
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||
Fixed Swaps/Futures
|
(43
|
)
|
|
(43
|
)
|
|
—
|
|
|||
Power:
|
|
|
|
|
|
||||||
Forwards
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
|||
Futures
|
(3
|
)
|
|
(3
|
)
|
|
—
|
|
|||
NGLs – Forwards/Swaps
|
(278
|
)
|
|
(278
|
)
|
|
—
|
|
|||
Refined Products – Futures
|
(10
|
)
|
|
(10
|
)
|
|
—
|
|
|||
Total commodity derivatives
|
(389
|
)
|
|
(383
|
)
|
|
(6
|
)
|
|||
Total liabilities
|
$
|
(788
|
)
|
|
$
|
(383
|
)
|
|
$
|
(405
|
)
|
|
Fair Value 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:
|
|
|
|
|
|
||||||
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
|
)
|
3.
|
ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
|
|
At December 5, 2019
|
||
Total current assets
|
$
|
548
|
|
Property, plant and equipment
|
2,544
|
|
|
Other non-current assets
|
574
|
|
|
Goodwill
|
230
|
|
|
Intangible assets
|
280
|
|
|
Total assets
|
4,176
|
|
|
|
|
||
Total current liabilities
|
480
|
|
|
Long-term debt, less current maturities
|
812
|
|
|
Other non-current liabilities
|
109
|
|
|
Total liabilities
|
1,401
|
|
|
|
|
||
Noncontrolling interest
|
335
|
|
|
|
|
||
Partners’ capital
|
2,440
|
|
|
Total liabilities and partners’ capital
|
$
|
4,176
|
|
•
|
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 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.
|
|
Years Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
REVENUES
|
$
|
349
|
|
|
$
|
6,964
|
|
|
|
|
|
||||
COSTS AND EXPENSES
|
|
|
|
||||
Cost of products sold
|
305
|
|
|
5,806
|
|
||
Operating expenses
|
61
|
|
|
763
|
|
||
Depreciation, depletion and amortization
|
—
|
|
|
34
|
|
||
Selling, general and administrative
|
7
|
|
|
168
|
|
||
Impairment losses
|
—
|
|
|
285
|
|
||
Total costs and expenses
|
373
|
|
|
7,056
|
|
||
OPERATING LOSS
|
(24
|
)
|
|
(92
|
)
|
||
OTHER EXPENSE
|
|
|
|
||||
Interest expense, net
|
2
|
|
|
36
|
|
||
Loss on extinguishment of debt
|
20
|
|
|
—
|
|
||
Other, net
|
61
|
|
|
1
|
|
||
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE
|
(107
|
)
|
|
(129
|
)
|
||
Income tax expense
|
158
|
|
|
48
|
|
||
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES
|
$
|
(265
|
)
|
|
$
|
(177
|
)
|
4.
|
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Citrus
|
$
|
148
|
|
|
$
|
141
|
|
|
$
|
144
|
|
FEP
|
59
|
|
|
55
|
|
|
53
|
|
|||
MEP
|
15
|
|
|
31
|
|
|
38
|
|
|||
Other
|
76
|
|
|
117
|
|
|
(91
|
)
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
298
|
|
|
$
|
344
|
|
|
$
|
144
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Current assets
|
$
|
247
|
|
|
$
|
212
|
|
Property, plant and equipment, net
|
7,680
|
|
|
7,800
|
|
||
Other assets
|
40
|
|
|
39
|
|
||
Total assets
|
$
|
7,967
|
|
|
$
|
8,051
|
|
|
|
|
|
||||
Current liabilities
|
$
|
738
|
|
|
$
|
1,534
|
|
Non-current liabilities
|
3,242
|
|
|
3,439
|
|
||
Equity
|
3,987
|
|
|
3,078
|
|
||
Total liabilities and equity
|
$
|
7,967
|
|
|
$
|
8,051
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Revenue
|
$
|
1,192
|
|
|
$
|
1,249
|
|
|
$
|
1,358
|
|
Operating income
|
683
|
|
|
723
|
|
|
407
|
|
|||
Net income
|
443
|
|
|
460
|
|
|
145
|
|
5.
|
DEBT OBLIGATIONS:
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
ETO Debt
|
|
|
|
||||
9.70% Senior Notes due March 15, 2019
|
$
|
—
|
|
|
$
|
400
|
|
9.00% Senior Notes due April 15, 2019
|
—
|
|
|
450
|
|
||
5.50% Senior Notes due February 15, 2020 (1)
|
250
|
|
|
250
|
|
||
5.75% Senior Notes due September 1, 2020 (1)
|
400
|
|
|
400
|
|
||
4.15% Senior Notes due October 1, 2020 (1)
|
1,050
|
|
|
1,050
|
|
||
7.50% Senior Notes due October 15, 2020 (1)
|
1,135
|
|
|
—
|
|
||
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
|
|
||
4.25% Senior Notes due March 15, 2023
|
995
|
|
|
—
|
|
||
4.20% Senior Notes due September 15, 2023
|
500
|
|
|
500
|
|
||
4.50% Senior Notes due November 1, 2023
|
600
|
|
|
600
|
|
||
5.875% Senior Notes due January 15, 2024
|
1,127
|
|
|
—
|
|
||
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
|
|
||
4.50% Senior Notes due April 15, 2024
|
750
|
|
|
—
|
|
||
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
|
|
||
5.50% Senior Notes due June 1, 2027
|
956
|
|
|
—
|
|
||
4.00% Senior Notes due October 1, 2027
|
750
|
|
|
750
|
|
||
4.95% Senior Notes due June 15, 2028
|
1,000
|
|
|
1,000
|
|
||
5.25% Senior Notes due April 15, 2029
|
1,500
|
|
|
—
|
|
||
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
|
|
|
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
|
|
|
1,000
|
|
||
6.25% Senior Notes due April 15, 2049
|
1,750
|
|
|
—
|
|
||
Floating Rate Junior Subordinated Notes due November 1, 2066
|
546
|
|
|
546
|
|
||
ETO $2.00 billion Term Loan facility due October 2022
|
2,000
|
|
|
—
|
|
||
ETO $5.00 billion Revolving Credit Facility due December 2023
|
4,214
|
|
|
3,694
|
|
Unamortized premiums, discounts and fair value adjustments, net
|
(5
|
)
|
|
17
|
|
||
Deferred debt issuance costs
|
(207
|
)
|
|
(178
|
)
|
||
|
42,120
|
|
|
32,288
|
|
||
Transwestern Debt
|
|
|
|
||||
5.36% Senior Notes due December 9, 2020 (1)
|
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
|
|
|
|
||||
8.125% Senior Notes due June 1, 2019
|
—
|
|
|
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
|
11
|
|
|
14
|
|
||
|
246
|
|
|
399
|
|
||
Bakken Project Debt
|
|
|
|
||||
3.625% Senior Notes due April 1, 2022
|
650
|
|
|
—
|
|
||
3.90% Senior Notes due April 1, 2024
|
1,000
|
|
|
—
|
|
||
4.625% Senior Notes due April 1, 2029
|
850
|
|
|
—
|
|
||
Bakken $2.50 billion Credit Facility due August 2019
|
—
|
|
|
2,500
|
|
||
Unamortized premiums, discounts and fair value adjustments, net
|
(3
|
)
|
|
—
|
|
||
Deferred debt issuance costs
|
(16
|
)
|
|
(3
|
)
|
||
|
2,481
|
|
|
2,497
|
|
||
Sunoco LP Debt
|
|
|
|
||||
4.875% Senior Notes Due January 15, 2023
|
1,000
|
|
|
1,000
|
|
||
5.50% Senior Notes Due February 15, 2026
|
800
|
|
|
800
|
|
||
6.00% Senior Notes Due April 15, 2027
|
600
|
|
|
—
|
|
||
5.875% Senior Notes Due March 15, 2028
|
400
|
|
|
400
|
|
||
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023
|
162
|
|
|
700
|
|
||
Lease-related obligations
|
135
|
|
|
107
|
|
||
Deferred debt issuance costs
|
(26
|
)
|
|
(23
|
)
|
||
|
3,071
|
|
|
2,984
|
|
||
USAC Debt
|
|
|
|
||||
6.875% Senior Notes due April 1, 2026
|
725
|
|
|
725
|
|
||
6.875% Senior Notes due September 1, 2027
|
750
|
|
|
—
|
|
||
USAC $1.60 billion Revolving Credit Facility due April 2023
|
403
|
|
|
1,050
|
|
||
Deferred debt issuance costs
|
(26
|
)
|
|
(16
|
)
|
||
|
1,852
|
|
|
1,759
|
|
||
|
|
|
|
||||
Other
|
2
|
|
|
7
|
|
||
Total debt
|
50,346
|
|
|
40,508
|
|
||
Less: Current maturities of long-term debt
|
12
|
|
|
2,655
|
|
||
Long-term debt, less current maturities
|
$
|
50,334
|
|
|
$
|
37,853
|
|
(1)
|
As of December 31, 2019, 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 redeemed in January 2020.
|
2020
|
|
$
|
3,021
|
|
2021
|
|
1,412
|
|
|
2022
|
|
5,792
|
|
|
2023
|
|
8,960
|
|
|
2024
|
|
4,337
|
|
|
Thereafter
|
|
27,097
|
|
|
Total
|
|
$
|
50,619
|
|
•
|
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.
|
•
|
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) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0 to 1.0 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:
|
|
Preferred Unitholders
|
|
|
||||||||||||||||||||
|
Series A
|
|
Series B
|
|
Series C
|
|
Series D
|
|
Series E
|
|
Total
|
||||||||||||
Balance, December 31, 2016
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Distributions to partners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Partnership units issued for cash
|
937
|
|
|
542
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,479
|
|
||||||
Other, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net income
|
7
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
||||||
Balance, December 31, 2017
|
944
|
|
|
547
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,491
|
|
||||||
Distributions to partners
|
(44
|
)
|
|
(27
|
)
|
|
(18
|
)
|
|
(11
|
)
|
|
—
|
|
|
(100
|
)
|
||||||
Partnership units issued for cash
|
—
|
|
|
—
|
|
|
436
|
|
|
431
|
|
|
—
|
|
|
867
|
|
||||||
Other, net
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|
(3
|
)
|
||||||
Net income
|
59
|
|
|
36
|
|
|
23
|
|
|
15
|
|
|
—
|
|
|
133
|
|
||||||
Balance, December 31, 2018
|
958
|
|
|
556
|
|
|
440
|
|
|
434
|
|
|
—
|
|
|
2,388
|
|
||||||
Distributions to partners
|
(59
|
)
|
|
(37
|
)
|
|
(33
|
)
|
|
(34
|
)
|
|
(34
|
)
|
|
(197
|
)
|
||||||
Partnership units issued for cash
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
780
|
|
|
780
|
|
||||||
Other, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
||||||
Net income
|
59
|
|
|
37
|
|
|
33
|
|
|
34
|
|
|
41
|
|
|
204
|
|
||||||
Balance, December 31, 2019
|
$
|
958
|
|
|
$
|
556
|
|
|
$
|
440
|
|
|
$
|
434
|
|
|
$
|
786
|
|
|
$
|
3,174
|
|
Period Ended
|
|
Record Date
|
|
Payment Date
|
|
Series A (1)
|
|
Series B (1)
|
|
Series C
|
|
Series D
|
|
Series E
|
|
||||||||||
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
|
|
|
—
|
|
|
|||||
March 31, 2019
|
|
May 1, 2019
|
|
May 15, 2019
|
|
—
|
|
|
—
|
|
|
0.4609
|
|
|
0.4766
|
|
|
—
|
|
|
|||||
June 30, 2019
|
|
August 1, 2019
|
|
August 15, 2019
|
|
31.2500
|
|
|
33.1250
|
|
|
0.4609
|
|
|
0.4766
|
|
|
0.5806
|
|
*
|
|||||
September 30, 2019
|
|
November 1, 2019
|
|
November 15, 2019
|
|
—
|
|
|
—
|
|
|
0.4609
|
|
|
0.4766
|
|
|
0.4750
|
|
|
|||||
December 31, 2019
|
|
February 3, 2020
|
|
February 18, 2020
|
|
31.2500
|
|
|
33.1250
|
|
|
0.4609
|
|
|
0.4766
|
|
|
0.4750
|
|
|
*
|
Represent prorated initial distributions. Prorated initial distributions on the recently issued Series F and Series G preferred units will be payable in May 2020.
|
|
|
|
|
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, 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
|
|
|
March 31, 2019
|
|
May 7, 2019
|
|
May 15, 2019
|
|
0.8255
|
|
|
June 30, 2019
|
|
August 6, 2019
|
|
August 14, 2019
|
|
0.8255
|
|
|
September 30, 2019
|
|
November 5, 2019
|
|
November 19, 2019
|
|
0.8255
|
|
|
December 31, 2019
|
|
February 7, 2020
|
|
February 19, 2020
|
|
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
|
|
|
March 31, 2019
|
|
April 29, 2019
|
|
May 10, 2019
|
|
0.5250
|
|
|
June 30, 2019
|
|
July 29, 2019
|
|
August 9, 2019
|
|
0.5250
|
|
|
September 30, 2019
|
|
October 28, 2019
|
|
November 8, 2019
|
|
0.5250
|
|
|
December 31, 2019
|
|
January 27, 2020
|
|
February 7, 2020
|
|
0.5250
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Available-for-sale securities
|
$
|
13
|
|
|
$
|
2
|
|
Foreign currency translation adjustment
|
(5
|
)
|
|
(5
|
)
|
||
Actuarial loss related to pensions and other postretirement benefits
|
(25
|
)
|
|
(48
|
)
|
||
Investments in unconsolidated affiliates, net
|
(1
|
)
|
|
9
|
|
||
Total AOCI, net of tax
|
$
|
(18
|
)
|
|
$
|
(42
|
)
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Available-for-sale securities
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
Foreign currency translation adjustment
|
2
|
|
|
2
|
|
||
Actuarial loss relating to pension and other postretirement benefits
|
8
|
|
|
12
|
|
||
Total
|
$
|
9
|
|
|
$
|
13
|
|
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 as of December 31, 2018
|
2.1
|
|
|
$
|
29.15
|
|
|
1.4
|
|
|
$
|
14.98
|
|
Awards granted
|
0.7
|
|
|
30.70
|
|
|
0.7
|
|
|
15.88
|
|
||
Awards vested
|
(0.5
|
)
|
|
30.04
|
|
|
(0.3
|
)
|
|
13.06
|
|
||
Awards forfeited
|
(0.2
|
)
|
|
28.16
|
|
|
—
|
|
|
16.78
|
|
||
Unvested awards as of December 31, 2019
|
2.1
|
|
|
29.21
|
|
|
1.8
|
|
|
15.09
|
|
9.
|
INCOME TAXES:
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Current expense (benefit):
|
|
|
|
|
|
||||||
Federal
|
$
|
(20
|
)
|
|
$
|
(7
|
)
|
|
$
|
53
|
|
State
|
(1
|
)
|
|
20
|
|
|
(16
|
)
|
|||
Total
|
(21
|
)
|
|
13
|
|
|
37
|
|
|||
Deferred expense (benefit):
|
|
|
|
|
|
||||||
Federal
|
176
|
|
|
183
|
|
|
(2,025
|
)
|
|||
State
|
45
|
|
|
(191
|
)
|
|
184
|
|
|||
Total
|
221
|
|
|
(8
|
)
|
|
(1,841
|
)
|
|||
Total income tax expense (benefit)
|
$
|
200
|
|
|
$
|
5
|
|
|
$
|
(1,804
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Income tax expense at United States statutory rate
|
$
|
1,131
|
|
|
$
|
849
|
|
|
$
|
402
|
|
Increase (reduction) in income taxes resulting from:
|
|
|
|
|
|
||||||
Partnership earnings not subject to tax
|
(940
|
)
|
|
(718
|
)
|
|
(626
|
)
|
|||
Federal rate change
|
—
|
|
|
—
|
|
|
(1,784
|
)
|
|||
Goodwill impairments
|
—
|
|
|
—
|
|
|
208
|
|
|||
State income taxes (net of federal income tax effects)
|
14
|
|
|
(125
|
)
|
|
123
|
|
|||
Dividend received deduction
|
(3
|
)
|
|
(5
|
)
|
|
(14
|
)
|
|||
Change in tax status of subsidiary
|
—
|
|
|
—
|
|
|
(124
|
)
|
|||
Other
|
(2
|
)
|
|
4
|
|
|
11
|
|
|||
Income tax expense (benefit)
|
$
|
200
|
|
|
$
|
5
|
|
|
$
|
(1,804
|
)
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Deferred income tax assets:
|
|
|
|
||||
Net operating losses, alternative minimum tax credit and other carryforwards
|
$
|
669
|
|
|
$
|
768
|
|
Pension and other postretirement benefits
|
—
|
|
|
34
|
|
||
Long-term debt
|
—
|
|
|
13
|
|
||
Other
|
62
|
|
|
181
|
|
||
Total deferred income tax assets
|
731
|
|
|
996
|
|
||
Valuation allowance
|
(49
|
)
|
|
(96
|
)
|
||
Net deferred income tax assets
|
$
|
682
|
|
|
$
|
900
|
|
|
|
|
|
||||
Deferred income tax liabilities:
|
|
|
|
||||
Property, plant and equipment
|
$
|
(258
|
)
|
|
$
|
(742
|
)
|
Investments in affiliates
|
(3,452
|
)
|
|
(2,869
|
)
|
||
Trademarks
|
(72
|
)
|
|
(63
|
)
|
||
Other
|
(13
|
)
|
|
(110
|
)
|
||
Total deferred income tax liabilities
|
(3,795
|
)
|
|
(3,784
|
)
|
||
Net deferred income taxes
|
$
|
(3,113
|
)
|
|
$
|
(2,884
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Balance at beginning of year
|
$
|
624
|
|
|
$
|
609
|
|
|
$
|
615
|
|
Additions attributable to tax positions taken in the current year
|
—
|
|
|
8
|
|
|
—
|
|
|||
Additions attributable to tax positions taken in prior years
|
11
|
|
|
7
|
|
|
28
|
|
|||
Reduction attributable to tax positions taken in prior years
|
(541
|
)
|
|
—
|
|
|
(25
|
)
|
|||
Lapse of statute
|
—
|
|
|
—
|
|
|
(9
|
)
|
|||
Balance at end of year
|
$
|
94
|
|
|
$
|
624
|
|
|
$
|
609
|
|
10.
|
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
ROW expense
|
$
|
45
|
|
|
$
|
46
|
|
|
$
|
46
|
|
•
|
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 be contractually responsible for contamination caused by other parties.
|
•
|
certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
|
•
|
legacy sites related to Sunoco that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Current
|
$
|
43
|
|
|
$
|
42
|
|
Non-current
|
274
|
|
|
295
|
|
||
Total environmental liabilities
|
$
|
317
|
|
|
$
|
337
|
|
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.
|
|
Contract Liabilities
|
||
Balance, January 1, 2018
|
$
|
221
|
|
Additions
|
765
|
|
|
Revenue recognized
|
(592
|
)
|
|
Balance, December 31, 2018
|
394
|
|
|
Additions
|
643
|
|
|
Revenue recognized
|
(679
|
)
|
|
Balance, December 31, 2019
|
$
|
358
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
Contract balances:
|
|
|
|
||||
Contract asset
|
$
|
117
|
|
|
$
|
75
|
|
Accounts receivable from contracts with customers
|
366
|
|
|
347
|
|
||
Contract liability
|
—
|
|
|
1
|
|
|
|
Years Ending December 31,
|
|
|
|
|
||||||||||||||
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
||||||||||
Revenue expected to be recognized on contracts with customers existing as of December 31, 2019
|
|
$
|
5,913
|
|
|
$
|
5,056
|
|
|
$
|
4,672
|
|
|
$
|
25,059
|
|
|
$
|
40,700
|
|
•
|
Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.
|
•
|
Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.
|
•
|
Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.
|
•
|
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.
|
LEASE ACCOUNTING:
|
|
December 31, 2019
|
||
Operating leases:
|
|
||
Lease right-of-use assets, net
|
$
|
848
|
|
Operating lease current liabilities
|
54
|
|
|
Accrued and other current liabilities
|
1
|
|
|
Non-current operating lease liabilities
|
816
|
|
|
Finance leases:
|
|
||
Property, plant and equipment, net
|
$
|
1
|
|
Lease right-of-use assets, net
|
29
|
|
|
Accrued and other current liabilities
|
1
|
|
|
Current maturities of long-term debt
|
6
|
|
|
Long-term debt, less current maturities
|
26
|
|
|
Other non-current liabilities
|
2
|
|
|
|
Income Statement Location
|
|
Year Ended December 31, 2019
|
||
Operating lease costs:
|
|
|
||||
Operating lease cost
|
|
Cost of goods sold
|
|
$
|
28
|
|
Operating lease cost
|
|
Operating expenses
|
|
72
|
|
|
Operating lease cost
|
|
Selling, general and administrative
|
|
16
|
|
|
Total operating lease costs
|
|
116
|
|
|||
Finance lease costs:
|
|
|
||||
Amortization of lease assets
|
|
Depreciation, depletion and amortization
|
|
6
|
|
|
Interest on lease liabilities
|
|
Interest expense, net of capitalized interest
|
|
1
|
|
|
Total finance lease costs
|
|
7
|
|
|||
Short-term lease cost
|
|
Operating expenses
|
|
42
|
|
|
Variable lease cost
|
|
Operating expenses
|
|
17
|
|
|
Lease costs, gross
|
|
182
|
|
|||
Less: Sublease income
|
|
Other revenue
|
|
47
|
|
|
Lease costs, net
|
|
$
|
135
|
|
|
December 31, 2019
|
|
Weighted-average remaining lease term (years):
|
|
|
Operating leases
|
22
|
|
Finance leases
|
5
|
|
Weighted-average discount rate (%):
|
|
|
Operating leases
|
5
|
%
|
Finance leases
|
5
|
%
|
|
Year Ended December 31, 2019
|
||
Operating cash flows from operating leases
|
$
|
(158
|
)
|
Lease assets obtained in exchange for new finance lease liabilities
|
28
|
|
|
Lease assets obtained in exchange for new operating lease liabilities
|
39
|
|
|
Operating leases
|
|
Finance leases
|
|
Total
|
||||||
2020
|
$
|
98
|
|
|
$
|
8
|
|
|
$
|
106
|
|
2021
|
89
|
|
|
8
|
|
|
97
|
|
|||
2022
|
77
|
|
|
8
|
|
|
85
|
|
|||
2023
|
71
|
|
|
7
|
|
|
78
|
|
|||
2024
|
68
|
|
|
4
|
|
|
72
|
|
|||
Thereafter
|
1,141
|
|
|
5
|
|
|
1,146
|
|
|||
Total lease payments
|
1,544
|
|
|
40
|
|
|
1,584
|
|
|||
Less: present value discount
|
674
|
|
|
5
|
|
|
679
|
|
|||
Present value of lease liabilities
|
$
|
870
|
|
|
$
|
35
|
|
|
$
|
905
|
|
|
Lease Payments
|
||
2020
|
$
|
125
|
|
2021
|
99
|
|
|
2022
|
62
|
|
|
2023
|
7
|
|
|
2024
|
2
|
|
|
Thereafter
|
7
|
|
|
Total undiscounted cash flows
|
$
|
302
|
|
13.
|
DERIVATIVE ASSETS AND LIABILITIES:
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||
|
Notional
Volume
|
|
Maturity
|
|
Notional
Volume
|
|
Maturity
|
||
Mark-to-Market Derivatives
|
|
|
|
|
|
|
|
||
(Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
||
Fixed Swaps/Futures
|
1,483
|
|
|
2020
|
|
468
|
|
|
2019
|
Basis Swaps IFERC/NYMEX(1)
|
(35,208
|
)
|
|
2020-2024
|
|
16,845
|
|
|
2019-2020
|
Options – Puts
|
—
|
|
|
—
|
|
10,000
|
|
|
2019
|
Power (Megawatt):
|
|
|
|
|
|
|
|
||
Forwards
|
3,213,450
|
|
|
2020-2029
|
|
3,141,520
|
|
|
2019
|
Futures
|
(353,527
|
)
|
|
2020
|
|
56,656
|
|
|
2019-2021
|
Options – Puts
|
51,615
|
|
|
2020
|
|
18,400
|
|
|
2019
|
Options – Calls
|
(2,704,330
|
)
|
|
2020-2021
|
|
284,800
|
|
|
2019
|
(Non-Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
||
Basis Swaps IFERC/NYMEX
|
(18,923
|
)
|
|
2020-2022
|
|
(30,228
|
)
|
|
2019-2021
|
Swing Swaps IFERC
|
(9,265
|
)
|
|
2020
|
|
54,158
|
|
|
2019-2020
|
Fixed Swaps/Futures
|
(3,085
|
)
|
|
2020-2021
|
|
(1,068
|
)
|
|
2019-2021
|
Forward Physical Contracts
|
(13,364
|
)
|
|
2020-2021
|
|
(123,254
|
)
|
|
2019-2020
|
NGL (MBbls) – Forwards/Swaps
|
(1,300
|
)
|
|
2020-2021
|
|
(2,135
|
)
|
|
2019
|
Crude (MBbls) – Forwards/Swaps
|
4,465
|
|
|
2020
|
|
20,888
|
|
|
2019
|
Refined Products (MBbls) – Futures
|
(2,473
|
)
|
|
2020-2021
|
|
(1,403
|
)
|
|
2019
|
Corn (thousand bushels)
|
(1,210
|
)
|
|
2020
|
|
(1,920
|
)
|
|
2019
|
Fair Value Hedging Derivatives
|
|
|
|
|
|
|
|
||
(Non-Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
||
Basis Swaps IFERC/NYMEX
|
(31,780
|
)
|
|
2020
|
|
(17,445
|
)
|
|
2019
|
Fixed Swaps/Futures
|
(31,780
|
)
|
|
2020
|
|
(17,445
|
)
|
|
2019
|
Hedged Item – Inventory
|
31,780
|
|
|
2020
|
|
17,445
|
|
|
2019
|
(1)
|
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
|
Term
|
|
Type (1)
|
|
Notional Amount Outstanding
|
||||||
December 31, 2019
|
|
December 31, 2018
|
||||||||
March 2019
|
|
Pay a floating rate and receive a fixed rate of 1.42%
|
|
$
|
—
|
|
|
$
|
300
|
|
July 2019 (2)
|
|
Forward-starting to pay a fixed rate of 3.56% and receive a floating rate
|
|
—
|
|
|
400
|
|
||
July 2020 (2)(3)
|
|
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
|
|
|
400
|
|
||
July 2022 (2)
|
|
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
|
|
400
|
|
|
—
|
|
(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.
|
(3)
|
The July 2020 interest rate swaps were terminated in January 2020.
|
|
Fair Value of Derivative Instruments
|
||||||||||||||
|
Asset Derivatives
|
|
Liability Derivatives
|
||||||||||||
|
December 31, 2019
|
|
December 31, 2018
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives (margin deposits)
|
$
|
24
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(13
|
)
|
|
24
|
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives (margin deposits)
|
319
|
|
|
402
|
|
|
(350
|
)
|
|
(397
|
)
|
||||
Commodity derivatives
|
41
|
|
|
158
|
|
|
(39
|
)
|
|
(173
|
)
|
||||
Interest rate derivatives
|
—
|
|
|
—
|
|
|
(399
|
)
|
|
(163
|
)
|
||||
|
360
|
|
|
560
|
|
|
(788
|
)
|
|
(733
|
)
|
||||
Total derivatives
|
$
|
384
|
|
|
$
|
560
|
|
|
$
|
(788
|
)
|
|
$
|
(746
|
)
|
|
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,
|
||||||||||
|
|
|
2019
|
|
2018
|
|
2017
|
||||||
Derivatives in fair value hedging relationships (including hedged item):
|
|
|
|
|
|
|
|
||||||
Commodity derivatives
|
Cost of products sold
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
$
|
26
|
|
|
Location of Gain (Loss) Recognized in Income on Derivatives
|
|
Amount of Gain (Loss) Recognized in Income on Derivatives
|
||||||||||
|
|
|
Years Ended December 31,
|
||||||||||
|
|
|
2019
|
|
2018
|
|
2017
|
||||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||
Commodity derivatives – Trading
|
Cost of products sold
|
|
$
|
21
|
|
|
$
|
32
|
|
|
$
|
31
|
|
Commodity derivatives – Non-trading
|
Cost of products sold
|
|
(78
|
)
|
|
(102
|
)
|
|
5
|
|
|||
Interest rate derivatives
|
Gains (losses) on interest rate derivatives
|
|
(241
|
)
|
|
47
|
|
|
(37
|
)
|
|||
Embedded derivatives
|
Other, net
|
|
—
|
|
|
—
|
|
|
1
|
|
|||
Total
|
|
|
$
|
(298
|
)
|
|
$
|
(23
|
)
|
|
$
|
—
|
|
14.
|
RETIREMENT BENEFITS:
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||||||||||
|
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
|
|
|
$
|
37
|
|
|
$
|
198
|
|
|
$
|
1
|
|
|
$
|
47
|
|
|
$
|
156
|
|
Service cost
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||
Interest cost
|
—
|
|
|
1
|
|
|
7
|
|
|
—
|
|
|
1
|
|
|
5
|
|
||||||
Amendments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60
|
|
||||||
Benefits paid, net
|
—
|
|
|
(7
|
)
|
|
(16
|
)
|
|
—
|
|
|
(7
|
)
|
|
(17
|
)
|
||||||
Actuarial (gain) loss and other
|
—
|
|
|
—
|
|
|
18
|
|
|
—
|
|
|
(4
|
)
|
|
(7
|
)
|
||||||
Benefit obligation at end of period
|
1
|
|
|
31
|
|
|
208
|
|
|
1
|
|
|
37
|
|
|
198
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Change in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fair value of plan assets at beginning of period
|
1
|
|
|
—
|
|
|
241
|
|
|
1
|
|
|
—
|
|
|
257
|
|
||||||
Return on plan assets and other
|
—
|
|
|
—
|
|
|
35
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
||||||
Employer contributions
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
9
|
|
||||||
Benefits paid, net
|
—
|
|
|
—
|
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
||||||
Fair value of plan assets at end of period
|
1
|
|
|
—
|
|
|
270
|
|
|
1
|
|
|
—
|
|
|
241
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amount underfunded (overfunded) at end of period
|
$
|
—
|
|
|
$
|
31
|
|
|
$
|
(62
|
)
|
|
$
|
—
|
|
|
$
|
37
|
|
|
$
|
(43
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amounts recognized in the consolidated balance sheets consist of:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Non-current assets
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
88
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
68
|
|
Current liabilities
|
—
|
|
|
(5
|
)
|
|
(2
|
)
|
|
—
|
|
|
(6
|
)
|
|
(2
|
)
|
||||||
Non-current liabilities
|
—
|
|
|
(26
|
)
|
|
(24
|
)
|
|
—
|
|
|
(31
|
)
|
|
(23
|
)
|
||||||
|
$
|
—
|
|
|
$
|
(31
|
)
|
|
$
|
62
|
|
|
$
|
—
|
|
|
$
|
(37
|
)
|
|
$
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial gain (loss)
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
(5
|
)
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
(7
|
)
|
Prior service cost
|
—
|
|
|
—
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|
66
|
|
||||||
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
35
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
59
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||||||||
|
Pension Benefits
|
|
|
|
Pension Benefits
|
|
|
||||||||||||||
|
Funded Plans
|
|
Unfunded Plans
|
|
Other Postretirement Benefits
|
|
Funded Plans
|
|
Unfunded Plans
|
|
Other Postretirement Benefits
|
||||||||||
Projected benefit obligation
|
$
|
—
|
|
|
$
|
31
|
|
|
N/A
|
|
|
$
|
—
|
|
|
$
|
37
|
|
|
N/A
|
|
Accumulated benefit obligation
|
1
|
|
|
31
|
|
|
208
|
|
|
1
|
|
|
37
|
|
|
198
|
|
||||
Fair value of plan assets
|
1
|
|
|
—
|
|
|
270
|
|
|
1
|
|
|
—
|
|
|
241
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||
Net periodic benefit cost:
|
|
|
|
|
|
|
|
||||||||
Service cost
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Interest cost
|
1
|
|
|
7
|
|
|
1
|
|
|
5
|
|
||||
Expected return on plan assets
|
—
|
|
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
||||
Prior service cost amortization
|
—
|
|
|
26
|
|
|
—
|
|
|
16
|
|
||||
Net periodic benefit cost
|
$
|
1
|
|
|
$
|
24
|
|
|
$
|
1
|
|
|
$
|
12
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||
Discount rate
|
4.07
|
%
|
|
2.71
|
%
|
|
4.02
|
%
|
|
3.40
|
%
|
Rate of compensation increase
|
—
|
|
|
—
|
|
|
N/A
|
|
|
N/A
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||
Discount rate
|
3.29
|
%
|
|
3.76
|
%
|
|
3.52
|
%
|
|
3.51
|
%
|
Expected return on assets:
|
|
|
|
|
|
|
|
||||
Tax exempt accounts
|
3.26
|
%
|
|
7.00
|
%
|
|
3.26
|
%
|
|
6.63
|
%
|
Taxable accounts
|
—
|
|
|
4.75
|
%
|
|
N/A
|
|
|
4.50
|
%
|
Rate of compensation increase
|
—
|
|
|
—
|
|
|
N/A
|
|
|
N/A
|
|
|
December 31,
|
||||
|
2019
|
|
2018
|
||
Health care cost trend rate
|
7.25
|
%
|
|
7.15
|
%
|
Rate to which the cost trend is assumed to decline (the ultimate trend rate)
|
4.83
|
%
|
|
4.82
|
%
|
Year that the rate reaches the ultimate trend rate
|
2026
|
|
|
2024
|
|
|
|
|
Fair Value Measurements at December 31, 2019
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Mutual funds(1)
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Comprised of approximately 100% equities as of December 31, 2019.
|
|
|
|
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, 2019
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Asset category:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
14
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mutual funds(1)
|
177
|
|
|
177
|
|
|
—
|
|
|
—
|
|
||||
Fixed income securities
|
79
|
|
|
—
|
|
|
79
|
|
|
—
|
|
||||
Total
|
$
|
270
|
|
|
$
|
191
|
|
|
$
|
79
|
|
|
$
|
—
|
|
(1)
|
Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2019.
|
|
|
|
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.
|
Years
|
|
Pension Benefits - Unfunded Plans (1)
|
|
Other Postretirement Benefits (Gross, Before Medicare Part D)
|
||||
2020
|
|
$
|
5
|
|
|
$
|
20
|
|
2021
|
|
5
|
|
|
20
|
|
||
2022
|
|
4
|
|
|
19
|
|
||
2023
|
|
4
|
|
|
18
|
|
||
2024
|
|
3
|
|
|
15
|
|
||
2025 - 2029
|
|
10
|
|
|
67
|
|
15.
|
RELATED PARTY TRANSACTIONS:
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues from related companies
|
$
|
492
|
|
|
$
|
431
|
|
|
$
|
303
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Accounts receivable from related companies:
|
|
|
|
||||
ET
|
$
|
8
|
|
|
$
|
65
|
|
FGT
|
50
|
|
|
25
|
|
||
Phillips 66
|
36
|
|
|
42
|
|
||
Traverse Rover LLC
|
42
|
|
|
—
|
|
||
Other
|
39
|
|
|
44
|
|
||
Total accounts receivable from related companies
|
$
|
175
|
|
|
$
|
176
|
|
|
|
|
|
||||
Accounts payable to related companies:
|
|
|
|
||||
ET
|
$
|
—
|
|
|
$
|
59
|
|
Other
|
27
|
|
|
60
|
|
||
Total accounts payable to related companies
|
$
|
27
|
|
|
$
|
119
|
|
16.
|
REPORTABLE SEGMENTS:
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Intrastate transportation and storage:
|
|
|
|
|
|
||||||
Revenues from external customers
|
$
|
2,749
|
|
|
$
|
3,428
|
|
|
$
|
2,891
|
|
Intersegment revenues
|
350
|
|
|
309
|
|
|
192
|
|
|||
|
3,099
|
|
|
3,737
|
|
|
3,083
|
|
|||
Interstate transportation and storage:
|
|
|
|
|
|
||||||
Revenues from external customers
|
1,941
|
|
|
1,664
|
|
|
1,112
|
|
|||
Intersegment revenues
|
22
|
|
|
18
|
|
|
19
|
|
|||
|
1,963
|
|
|
1,682
|
|
|
1,131
|
|
|||
Midstream:
|
|
|
|
|
|
||||||
Revenues from external customers
|
2,268
|
|
|
2,090
|
|
|
2,510
|
|
|||
Intersegment revenues
|
3,751
|
|
|
5,432
|
|
|
4,433
|
|
|||
|
6,019
|
|
|
7,522
|
|
|
6,943
|
|
|||
NGL and refined products transportation and services:
|
|
|
|
|
|
||||||
Revenues from external customers
|
9,920
|
|
|
10,119
|
|
|
7,885
|
|
|||
Intersegment revenues
|
1,721
|
|
|
1,004
|
|
|
763
|
|
|||
|
11,641
|
|
|
11,123
|
|
|
8,648
|
|
|||
Crude oil transportation and services:
|
|
|
|
|
|
||||||
Revenues from external customers
|
18,307
|
|
|
17,236
|
|
|
11,672
|
|
|||
Intersegment revenues
|
—
|
|
|
96
|
|
|
31
|
|
|||
|
18,307
|
|
|
17,332
|
|
|
11,703
|
|
|||
Investment in Sunoco LP:
|
|
|
|
|
|
||||||
Revenues from external customers
|
16,590
|
|
|
16,982
|
|
|
11,713
|
|
|||
Intersegment revenues
|
6
|
|
|
12
|
|
|
10
|
|
|||
|
16,596
|
|
|
16,994
|
|
|
11,723
|
|
|||
Investment in USAC:
|
|
|
|
|
|
||||||
Revenues from external customers
|
678
|
|
|
495
|
|
|
—
|
|
|||
Intersegment revenues
|
20
|
|
|
13
|
|
|
—
|
|
|||
|
698
|
|
|
508
|
|
|
—
|
|
|||
All other:
|
|
|
|
|
|
||||||
Revenues from external customers
|
1,579
|
|
|
2,073
|
|
|
2,740
|
|
|||
Intersegment revenues
|
81
|
|
|
155
|
|
|
161
|
|
|||
|
1,660
|
|
|
2,228
|
|
|
2,901
|
|
|||
Eliminations
|
(5,951
|
)
|
|
(7,039
|
)
|
|
(5,609
|
)
|
|||
Total revenues
|
$
|
54,032
|
|
|
$
|
54,087
|
|
|
$
|
40,523
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Cost of products sold:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
1,909
|
|
|
$
|
2,665
|
|
|
$
|
2,327
|
|
Midstream
|
3,570
|
|
|
5,145
|
|
|
4,761
|
|
|||
NGL and refined products transportation and services
|
8,393
|
|
|
8,462
|
|
|
6,508
|
|
|||
Crude oil transportation and services
|
14,649
|
|
|
14,439
|
|
|
9,826
|
|
|||
Investment in Sunoco LP
|
15,380
|
|
|
15,872
|
|
|
10,615
|
|
|||
Investment in USAC
|
91
|
|
|
67
|
|
|
—
|
|
|||
All other
|
1,496
|
|
|
2,006
|
|
|
2,509
|
|
|||
Eliminations
|
(5,885
|
)
|
|
(6,998
|
)
|
|
(5,580
|
)
|
|||
Total cost of products sold
|
$
|
39,603
|
|
|
$
|
41,658
|
|
|
$
|
30,966
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Depreciation, depletion and amortization:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
184
|
|
|
$
|
169
|
|
|
$
|
147
|
|
Interstate transportation and storage
|
387
|
|
|
334
|
|
|
254
|
|
|||
Midstream
|
1,065
|
|
|
1,006
|
|
|
954
|
|
|||
NGL and refined products transportation and services
|
613
|
|
|
466
|
|
|
401
|
|
|||
Crude oil transportation and services
|
430
|
|
|
445
|
|
|
402
|
|
|||
Investment in Sunoco LP
|
181
|
|
|
167
|
|
|
169
|
|
|||
Investment in USAC
|
231
|
|
|
169
|
|
|
—
|
|
|||
All other
|
33
|
|
|
87
|
|
|
214
|
|
|||
Total depreciation, depletion and amortization
|
$
|
3,124
|
|
|
$
|
2,843
|
|
|
$
|
2,541
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Equity in earnings (losses) of unconsolidated affiliates:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
18
|
|
|
$
|
19
|
|
|
$
|
(156
|
)
|
Interstate transportation and storage
|
222
|
|
|
227
|
|
|
236
|
|
|||
Midstream
|
20
|
|
|
26
|
|
|
20
|
|
|||
NGL and refined products transportation and services
|
51
|
|
|
64
|
|
|
33
|
|
|||
Crude oil transportation and services
|
(3
|
)
|
|
6
|
|
|
4
|
|
|||
All other
|
(10
|
)
|
|
2
|
|
|
7
|
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
298
|
|
|
$
|
344
|
|
|
$
|
144
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
999
|
|
|
$
|
927
|
|
|
$
|
626
|
|
Interstate transportation and storage
|
1,792
|
|
|
1,680
|
|
|
1,274
|
|
|||
Midstream
|
1,599
|
|
|
1,627
|
|
|
1,481
|
|
|||
NGL and refined products transportation and services
|
2,663
|
|
|
1,979
|
|
|
1,641
|
|
|||
Crude oil transportation and services
|
2,949
|
|
|
2,330
|
|
|
1,379
|
|
|||
Investment in Sunoco LP
|
665
|
|
|
638
|
|
|
732
|
|
|||
Investment in USAC
|
420
|
|
|
289
|
|
|
—
|
|
|||
All other
|
104
|
|
|
76
|
|
|
219
|
|
|||
Total Segment Adjusted EBITDA
|
11,191
|
|
|
9,546
|
|
|
7,352
|
|
|||
Depreciation, depletion and amortization
|
(3,124
|
)
|
|
(2,843
|
)
|
|
(2,541
|
)
|
|||
Interest expense, net of interest capitalized
|
(2,257
|
)
|
|
(1,709
|
)
|
|
(1,575
|
)
|
|||
Impairment losses
|
(74
|
)
|
|
(431
|
)
|
|
(1,039
|
)
|
|||
Gains (losses) on interest rate derivatives
|
(241
|
)
|
|
47
|
|
|
(37
|
)
|
|||
Non-cash compensation expense
|
(111
|
)
|
|
(105
|
)
|
|
(99
|
)
|
|||
Unrealized gains (losses) on commodity risk management activities
|
(4
|
)
|
|
(11
|
)
|
|
59
|
|
|||
Inventory valuation adjustments
|
79
|
|
|
(85
|
)
|
|
24
|
|
|||
Losses on extinguishments of debt
|
(2
|
)
|
|
(109
|
)
|
|
(42
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
(621
|
)
|
|
(655
|
)
|
|
(716
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
298
|
|
|
344
|
|
|
144
|
|
|||
Impairment of investments in unconsolidated affiliates
|
—
|
|
|
—
|
|
|
(313
|
)
|
|||
Adjusted EBITDA related to discontinued operations
|
—
|
|
|
25
|
|
|
(223
|
)
|
|||
Other, net
|
252
|
|
|
30
|
|
|
154
|
|
|||
Income from continuing operations before income tax expense
|
5,386
|
|
|
4,044
|
|
|
1,148
|
|
|||
Income tax expense from continuing operations
|
(200
|
)
|
|
(5
|
)
|
|
1,804
|
|
|||
Income from continuing operations
|
5,186
|
|
|
4,039
|
|
|
2,952
|
|
|||
Loss from discontinued operations, net of income taxes
|
—
|
|
|
(265
|
)
|
|
(177
|
)
|
|||
Net income
|
$
|
5,186
|
|
|
$
|
3,774
|
|
|
$
|
2,775
|
|
|
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Segment assets:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
6,648
|
|
|
$
|
6,365
|
|
|
$
|
5,020
|
|
Interstate transportation and storage
|
18,111
|
|
|
15,081
|
|
|
15,316
|
|
|||
Midstream
|
20,070
|
|
|
19,745
|
|
|
20,004
|
|
|||
NGL and refined products transportation and services
|
19,145
|
|
|
18,267
|
|
|
17,600
|
|
|||
Crude oil transportation and services
|
18,915
|
|
|
18,022
|
|
|
17,730
|
|
|||
Investment in Sunoco LP
|
5,438
|
|
|
4,879
|
|
|
8,344
|
|
|||
Investment in USAC
|
3,730
|
|
|
3,775
|
|
|
—
|
|
|||
All other and eliminations
|
6,468
|
|
|
2,308
|
|
|
2,470
|
|
|||
Total segment assets
|
$
|
98,525
|
|
|
$
|
88,442
|
|
|
$
|
86,484
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Additions to property, plant and equipment (1):
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
124
|
|
|
$
|
344
|
|
|
$
|
175
|
|
Interstate transportation and storage
|
375
|
|
|
812
|
|
|
728
|
|
|||
Midstream
|
826
|
|
|
1,161
|
|
|
1,308
|
|
|||
NGL and refined products transportation and services
|
2,976
|
|
|
2,381
|
|
|
2,971
|
|
|||
Crude oil transportation and services
|
392
|
|
|
474
|
|
|
453
|
|
|||
Investment in Sunoco LP
|
148
|
|
|
103
|
|
|
103
|
|
|||
Investment in USAC
|
200
|
|
|
205
|
|
|
—
|
|
|||
All other
|
213
|
|
|
150
|
|
|
268
|
|
|||
Total additions to property, plant and equipment (1)
|
$
|
5,254
|
|
|
$
|
5,630
|
|
|
$
|
6,006
|
|
(1)
|
Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis).
|
|
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Advances to and investments in unconsolidated affiliates:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
88
|
|
|
$
|
83
|
|
|
$
|
85
|
|
Interstate transportation and storage
|
2,524
|
|
|
2,070
|
|
|
2,118
|
|
|||
Midstream
|
112
|
|
|
124
|
|
|
126
|
|
|||
NGL and refined products transportation and services
|
243
|
|
|
243
|
|
|
234
|
|
|||
Crude oil transportation and services
|
24
|
|
|
28
|
|
|
22
|
|
|||
All other
|
27
|
|
|
88
|
|
|
113
|
|
|||
Total advances to and investments in unconsolidated affiliates
|
$
|
3,018
|
|
|
$
|
2,636
|
|
|
$
|
2,698
|
|
17.
|
QUARTERLY FINANCIAL DATA (UNAUDITED):
|
|
Quarters Ended
|
|
|
||||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Total Year
|
||||||||||
2019:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
13,121
|
|
|
$
|
13,877
|
|
|
$
|
13,495
|
|
|
$
|
13,539
|
|
|
$
|
54,032
|
|
Operating income
|
1,928
|
|
|
1,827
|
|
|
1,834
|
|
|
1,696
|
|
|
7,285
|
|
|||||
Net income
|
1,281
|
|
|
1,281
|
|
|
1,224
|
|
|
1,400
|
|
|
5,186
|
|
|||||
Net income attributable to partners
|
1,012
|
|
|
1,002
|
|
|
951
|
|
|
1,119
|
|
|
4,084
|
|
|
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
|
|
18.
|
CONSOLIDATING GUARANTOR FINANCIAL INFORMATION
|
|
December 31, 2019
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
253
|
|
|
$
|
—
|
|
|
$
|
253
|
|
All other current assets
|
4,905
|
|
|
44,047
|
|
|
45,997
|
|
|
(88,042
|
)
|
|
6,907
|
|
|||||
Property, plant and equipment
|
—
|
|
|
—
|
|
|
69,971
|
|
|
—
|
|
|
69,971
|
|
|||||
Investments in unconsolidated affiliates
|
57,383
|
|
|
15,045
|
|
|
3,033
|
|
|
(72,443
|
)
|
|
3,018
|
|
|||||
All other assets
|
5,786
|
|
|
131
|
|
|
12,459
|
|
|
—
|
|
|
18,376
|
|
|||||
Total assets
|
$
|
68,074
|
|
|
$
|
59,223
|
|
|
$
|
131,713
|
|
|
$
|
(160,485
|
)
|
|
$
|
98,525
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
$
|
3,394
|
|
|
$
|
41,148
|
|
|
$
|
48,350
|
|
|
$
|
(85,811
|
)
|
|
$
|
7,081
|
|
Non-current liabilities
|
34,782
|
|
|
7,602
|
|
|
13,753
|
|
|
—
|
|
|
56,137
|
|
|||||
Noncontrolling interests
|
—
|
|
|
—
|
|
|
8,018
|
|
|
—
|
|
|
8,018
|
|
|||||
Total partners’ capital
|
29,898
|
|
|
10,473
|
|
|
61,592
|
|
|
(74,674
|
)
|
|
27,289
|
|
|||||
Total liabilities and equity
|
$
|
68,074
|
|
|
$
|
59,223
|
|
|
$
|
131,713
|
|
|
$
|
(160,485
|
)
|
|
$
|
98,525
|
|
|
December 31, 2018
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
418
|
|
|
$
|
—
|
|
|
$
|
418
|
|
All other current assets
|
4,070
|
|
|
36,889
|
|
|
73,336
|
|
|
(107,893
|
)
|
|
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
|
$
|
55,958
|
|
|
$
|
50,054
|
|
|
$
|
155,289
|
|
|
$
|
(172,859
|
)
|
|
$
|
88,442
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
$
|
3,430
|
|
|
$
|
33,517
|
|
|
$
|
80,731
|
|
|
$
|
(108,381
|
)
|
|
$
|
9,297
|
|
Non-current liabilities
|
24,787
|
|
|
7,605
|
|
|
10,132
|
|
|
—
|
|
|
42,524
|
|
|||||
Noncontrolling interests
|
—
|
|
|
—
|
|
|
7,903
|
|
|
—
|
|
|
7,903
|
|
|||||
Total partners’ capital
|
27,741
|
|
|
8,932
|
|
|
56,523
|
|
|
(64,478
|
)
|
|
28,718
|
|
|||||
Total liabilities and equity
|
$
|
55,958
|
|
|
$
|
50,054
|
|
|
$
|
155,289
|
|
|
$
|
(172,859
|
)
|
|
$
|
88,442
|
|
|
Year Ended December 31, 2019
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
54,032
|
|
|
$
|
—
|
|
|
$
|
54,032
|
|
Operating costs, expenses, and other
|
—
|
|
|
—
|
|
|
46,747
|
|
|
—
|
|
|
46,747
|
|
|||||
Operating income
|
—
|
|
|
—
|
|
|
7,285
|
|
|
—
|
|
|
7,285
|
|
|||||
Interest expense, net
|
(1,612
|
)
|
|
(374
|
)
|
|
(271
|
)
|
|
—
|
|
|
(2,257
|
)
|
|||||
Equity in earnings of unconsolidated affiliates
|
5,623
|
|
|
1,938
|
|
|
298
|
|
|
(7,561
|
)
|
|
298
|
|
|||||
Losses on debt extinguishment
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
|
|
(2
|
)
|
||||||
Losses on interest rate derivatives
|
(241
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(241
|
)
|
|||||
Other, net
|
314
|
|
|
3
|
|
|
(14
|
)
|
|
—
|
|
|
303
|
|
|||||
Income before income tax expense
|
4,084
|
|
|
1,567
|
|
|
7,296
|
|
|
(7,561
|
)
|
|
5,386
|
|
|||||
Income tax expense
|
—
|
|
|
—
|
|
|
200
|
|
|
—
|
|
|
200
|
|
|||||
Net income
|
4,084
|
|
|
1,567
|
|
|
7,096
|
|
|
(7,561
|
)
|
|
5,186
|
|
|||||
Less: Net income attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
1,051
|
|
|
—
|
|
|
1,051
|
|
|||||
Less: Net income attributable to redeemable noncontrolling interests
|
|
|
|
|
51
|
|
|
|
|
51
|
|
||||||||
Net income attributable to partners
|
$
|
4,084
|
|
|
$
|
1,567
|
|
|
$
|
5,994
|
|
|
$
|
(7,561
|
)
|
|
$
|
4,084
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other comprehensive income
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24
|
|
|
$
|
—
|
|
|
$
|
24
|
|
Comprehensive income
|
4,084
|
|
|
1,567
|
|
|
7,120
|
|
|
(7,561
|
)
|
|
5,210
|
|
|||||
Comprehensive income attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
1,051
|
|
|
—
|
|
|
1,051
|
|
|||||
Comprehensive income attributable to redeemable noncontrolling interests
|
|
|
|
|
51
|
|
|
|
|
51
|
|
||||||||
Comprehensive income attributable to partners
|
$
|
4,084
|
|
|
$
|
1,567
|
|
|
$
|
6,018
|
|
|
$
|
(7,561
|
)
|
|
$
|
4,108
|
|
|
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 extinguishments of debt
|
—
|
|
|
—
|
|
|
(109
|
)
|
|
—
|
|
|
(109
|
)
|
|||||
Gains on interest rate derivatives
|
47
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47
|
|
|||||
Other, net
|
—
|
|
|
—
|
|
|
69
|
|
|
—
|
|
|
69
|
|
|||||
Income from continuing operations before income tax expense
|
3,021
|
|
|
1,254
|
|
|
5,369
|
|
|
(5,600
|
)
|
|
4,044
|
|
|||||
Income tax expense from continuing operations
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
|||||
Net income from continuing operations
|
3,021
|
|
|
1,254
|
|
|
5,364
|
|
|
(5,600
|
)
|
|
4,039
|
|
|||||
Loss from discontinued operations, net of income taxes
|
—
|
|
|
—
|
|
|
(265
|
)
|
|
—
|
|
|
(265
|
)
|
|||||
Net income
|
3,021
|
|
|
1,254
|
|
|
5,099
|
|
|
(5,600
|
)
|
|
3,774
|
|
|||||
Less: Net income attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
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
|
|
|||||
Less: Comprehensive income attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
715
|
|
|
—
|
|
|
715
|
|
|||||
Less: Comprehensive income attributable to redeemable noncontrolling interests
|
—
|
|
|
—
|
|
|
39
|
|
|
—
|
|
|
39
|
|
|||||
Less: Comprehensive loss 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 investments in unconsolidated affiliates
|
—
|
|
|
—
|
|
|
(313
|
)
|
|
—
|
|
|
(313
|
)
|
|||||
Losses on extinguishments of debt
|
—
|
|
|
—
|
|
|
(42
|
)
|
|
—
|
|
|
(42
|
)
|
|||||
Losses on interest rate derivatives
|
—
|
|
|
—
|
|
|
(37
|
)
|
|
—
|
|
|
(37
|
)
|
|||||
Other, net
|
—
|
|
|
—
|
|
|
207
|
|
|
(1
|
)
|
|
206
|
|
|||||
Income from continuing operations before income tax benefit
|
2,564
|
|
|
1,085
|
|
|
1,306
|
|
|
(3,807
|
)
|
|
1,148
|
|
|||||
Income tax benefit from continuing operations
|
—
|
|
|
—
|
|
|
(1,804
|
)
|
|
—
|
|
|
(1,804
|
)
|
|||||
Net income from continuing operations
|
2,564
|
|
|
1,085
|
|
|
3,110
|
|
|
(3,807
|
)
|
|
2,952
|
|
|||||
Loss from discontinued operations, net of income taxes
|
—
|
|
|
—
|
|
|
(177
|
)
|
|
—
|
|
|
(177
|
)
|
|||||
Net income
|
2,564
|
|
|
1,085
|
|
|
2,933
|
|
|
(3,807
|
)
|
|
2,775
|
|
|||||
Less: Net income attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
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
|
|
|||||
Less: Comprehensive income attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
420
|
|
|
—
|
|
|
420
|
|
|||||
Less: 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, 2019
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash flows provided by operating activities
|
$
|
3,372
|
|
|
$
|
2,732
|
|
|
$
|
8,988
|
|
|
$
|
(6,841
|
)
|
|
$
|
8,251
|
|
Cash flows used in investing activities
|
(2,044
|
)
|
|
(2,732
|
)
|
|
(8,188
|
)
|
|
6,841
|
|
|
(6,123
|
)
|
|||||
Cash flows used in financing activities
|
(1,328
|
)
|
|
—
|
|
|
(965
|
)
|
|
—
|
|
|
(2,293
|
)
|
|||||
Change in cash
|
—
|
|
|
—
|
|
|
(165
|
)
|
|
—
|
|
|
(165
|
)
|
|||||
Cash at beginning of period
|
—
|
|
|
—
|
|
|
418
|
|
|
—
|
|
|
418
|
|
|||||
Cash at end of period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
253
|
|
|
$
|
—
|
|
|
$
|
253
|
|
|
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 provided by (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 financing activities
|
(324
|
)
|
|
277
|
|
|
619
|
|
|
—
|
|
|
572
|
|
|||||
Net decrease 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
|
|
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
|
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
|
Buffalo Gulf Coast Terminals LLC, a Delaware limited liability company
|
Buffalo Parent Gulf Coast Terminals 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
|
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
|
DAL-TEX Consulting, LLC, a Texas 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
|
ET Starfish Holdings, LLC
|
ET TexLa Holdings LLC
|
ETC Bayou Bridge Holdings, LLC, a Delaware limited liability company
|
ETC Champ Pipeline LLC
|
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 Gas Storage LLC
|
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, LLC, 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 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 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 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
|
Glass Mountain Holding, LLC, an Oklahoma limited liability company
|
Grayson Pipeline, L.L.C., an Oklahoma limited liability company
|
Greyhawk Gas Storage Company, L.L.C., a Delaware limited liability company
|
Gulf States Transmission LLC, a Louisiana limited liability company
|
Helios Assurance Company, Limited, a Limited Bermuda other
|
Heritage ETC GP, L.L.C., a Delaware limited liability company
|
Heritage ETC, L.P., a Delaware limited partnership
|
HFOTCO LLC, a Texas limited liability company
|
Houston Pipe Line Company LP, 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 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
|
J.C. Nolan Terminal 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
|
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 Marine Facilities 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
|
Materials Handling Solutions LLC, a Delaware limited liability company
|
Maurepas Holding, LLC, an Oklahoma limited liability company
|
Maurepas Pipeline, LLC, a Delaware limited liability company
|
Mi Vida JV LLC, a Delaware limited liability company
|
Mid-America Midstream Gas Services, L.L.C., an Oklahoma limited liability company
|
Mid Valley Pipeline Company LLC, an Ohio limited liability company
|
Midcontinent Express Pipeline LLC, a Delaware 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 Gas Services LP, a Delaware limited partnership
|
Regency GP LLC, a Delaware limited liability company
|
Regency GP LP, a Delaware limited partnership
|
Regency Hydrocarbons LLC, an Oklahoma limited liability company
|
Regency Intrastate Gas LP, a Delaware limited partnership
|
Regency Marcellus Gas Gathering 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 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
|
RGP Marketing LLC, a Texas limited liability company
|
RIGS GP LLC, a Delaware limited liability company
|
RIGS Haynesville Partnership Co., a Delaware partnership
|
Rocky Cliffs Pipeline, L.L.C., a Delaware limited liability company
|
Rose Rock Midstream Crude, L.P., a Delaware limited partnership
|
Rose Rock Midstream Energy GP, LLC, a Delaware limited liability company
|
Rose Rock Midstream Field Services, LLC, a Delaware limited liability company
|
Rose Rock Midstream Operating, LLC, a Delaware limited liability company
|
Rover Pipeline LLC, a Delaware limited liability company
|
RSS Water Services LLC, a Delaware limited liability company
|
SemCrude Pipeline, L.L.C., a Delaware limited liability company
|
SemDevelopment, L.L.C., a Delaware limited liability company
|
SemGas Gathering, L.L.C., an Oklahoma limited liability company
|
SemGas Storage, L.L.C., an Oklahoma limited liability company
|
SemGas, L.P., an Oklahoma limited partnership
|
SemKan, L.L.C., an Oklahoma 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
|
Starfish Pipeline Company, LLC, a Delaware limited liability company
|
Steuben Development Company, L.L.C., a Delaware limited liability company
|
Stingray Pipeline Company, L.L.C., 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 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 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 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 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 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
|
Sweeney Gathering, L.P., a Texas 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
|
Triton Gathering, 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
|
Wattenberg Holding, LLC, an Oklahoma limited liability company
|
Waha Express Pipeline, LLC, a Delaware limited liability company
|
West Cameron Dehydration Company, L.L.C., 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
|
White Cliffs Pipeline, L.L.C., a Delaware limited liability company
|
Wolverine Pipe Line Company, a Delaware corporation
|
Yellowstone Pipe Line Company, a Delaware corporation
|
Aloha Petroleum LLC, a Delaware limited liability company
|
Aloha Petroleum, Ltd., a Hawaii Corporation
|
J.C. Nolan Pipeline Co., LLC, a Delaware limited liability company
|
J.C. Nolan Terminal Co., LLC, a Delaware limited liability company
|
Sandford Oil Company 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
|
Sun LP Pipeline LLC, a Delaware limited liability company
|
Sun LP Terminals LLC, a Delaware 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
|
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
|
|