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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2016
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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73-1493906
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(state or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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Title of each class
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Name of each exchange on which registered
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Common Units
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New York Stock Exchange
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PAGE
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ITEM 1.
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ITEM 1A.
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ITEM 1B.
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ITEM 2.
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ITEM 3.
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ITEM 4.
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ITEM 5.
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ITEM 6.
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ITEM 7.
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ITEM 7A.
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ITEM 8.
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ITEM 9.
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ITEM 9A.
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ITEM 9B.
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ITEM 10.
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ITEM 11.
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ITEM 12.
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ITEM 13.
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ITEM 14.
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ITEM 15.
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ITEM 16.
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/d
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per day
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AmeriGas
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AmeriGas Partners, L.P.
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AOCI
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accumulated other comprehensive income (loss)
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Aqua – PVR
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Aqua – PVR Water Services, LLC
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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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Bcf
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billion cubic feet
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BG
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BG Group plc
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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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Citrus
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Citrus, LLC
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Coal Handling
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Coal Handling Solutions LLC, Kingsport Handling LLC, and Kingsport Services LLC, now known as Materials Handling Solutions LLC
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CrossCountry
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CrossCountry Energy, LLC
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DOE
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U.S. Department of Energy
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DOT
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U.S. Department of Transportation
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Eagle Rock
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Eagle Rock Energy Partners, L.P.
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ELG
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Edwards Lime Gathering LLC
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EPA
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U.S. Environmental Protection Agency
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ETC FEP
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ETC Fayetteville Express Pipeline, LLC
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ETC MEP
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ETC Midcontinent Express Pipeline, L.L.C.
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ETC OLP
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La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
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ETC Tiger
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ETC Tiger Pipeline, LLC
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ETE
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Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC
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ETE Holdings
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ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
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ET Interstate
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Energy Transfer Interstate Holdings, LLC
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ET Rover
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ET Rover Pipeline LLC
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ETP Credit Facility
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ETP’s $3.75 billion revolving credit facility
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ETP GP
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Energy Transfer Partners GP, L.P., the general partner of ETP
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ETP Holdco
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ETP Holdco Corporation
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ETP LLC
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Energy Transfer Partners, L.L.C., the general partner of ETP GP
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Exchange Act
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Securities Exchange Act of 1934
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FEP
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Fayetteville Express Pipeline LLC
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FERC
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Federal Energy Regulatory Commission
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FGT
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Florida Gas Transmission Company, LLC
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GAAP
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accounting principles generally accepted in the United States of America
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Gulf States
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Gulf States Transmission LLC
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HPC
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RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
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HOLP
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Heritage Operating, L.P.
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Hoover Energy
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Hoover Energy Partners, LP
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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 subsidiary of ETE
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LCL
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Lake Charles LNG Export Company, LLC
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LIBOR
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London Interbank Offered Rate
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LNG
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liquefied natural gas
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Lone Star
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Lone Star NGL LLC
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LPG
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liquefied petroleum gas
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MACS
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Mid-Atlantic Convenience Stores, LLC
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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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MMBtu
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million British thermal units
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MMcf
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million cubic feet
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MTBE
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methyl tertiary butyl ether
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NGL
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natural gas liquid, such as propane, butane and natural gasoline
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NYMEX
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New York Mercantile Exchange
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NYSE
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New York Stock Exchange
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ORS
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Ohio River System LLC
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OSHA
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federal Occupational Safety and Health Act
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OTC
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over-the-counter
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Panhandle
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Panhandle Eastern Pipe Line Company, LP and its subsidiaries
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PCBs
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polychlorinated biphenyls
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PennTex
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PennTex Midstream Partners, LP
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PES
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Philadelphia Energy Solutions
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PHMSA
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Pipeline Hazardous Materials Safety Administration
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Preferred Units
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ETP Series A cumulative convertible preferred units
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PVR
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PVR Partners, L.P.
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Ranch JV
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Ranch Westex JV LLC
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Regency
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Regency Energy Partners LP
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Retail Holdings
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ETP Retail Holdings, LLC, a joint venture between subsidiaries of ETC OLP and Sunoco, Inc.
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RIGS
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Regency Intrastate Gas System
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Sea Robin
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Sea Robin Pipeline Company, LLC, a subsidiary of Panhandle
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SEC
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Securities and Exchange Commission
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Southern Union
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Southern Union Company
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Southwest Gas
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Pan Gas Storage, LLC
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Sunoco GP
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Sunoco GP LLC, the general partner of Sunoco LP
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Sunoco Logistics
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Sunoco Logistics Partners L.P.
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Sunoco LP
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Sunoco LP (previously named Susser Petroleum Partners, LP)
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Sunoco Partners
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Sunoco Partners LLC, the general partner of Sunoco Logistics
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Susser
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Susser Holdings Corporation
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Transwestern
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Transwestern Pipeline Company, LLC
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TRRC
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Texas Railroad Commission
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Trunkline
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Trunkline Gas Company, LLC, a subsidiary of Panhandle
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•
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Natural gas operations, including the following:
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natural gas midstream and intrastate transportation and storage; and
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interstate natural gas transportation and storage through ET Interstate and Panhandle. ET Interstate is the parent company of Transwestern, ETC FEP, ETC Tiger, CrossCountry, ETC MEP and ET Rover. Panhandle is the parent company of the Trunkline and Sea Robin transmission systems.
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Liquids operations, including NGL transportation, storage and fractionation services.
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Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities through Sunoco Logistics.
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On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately
$627 million
in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana.
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•
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In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for
$760 million
plus working capital. The acquisition provides Sunoco Logistics with an approximately
2 million
barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol's crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a
50%
interest in SunVit Pipeline LLC ("SunVit"), which increased Sunoco Logistics' overall ownership of SunVit to
100%
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In February 2017, Sunoco Logistics formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics contributed its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp. contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Sunoco Logistics’ ownership percentage is approximately
85%
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Upon commencement of operations on the Bakken Pipeline, Sunoco Logistics will contribute its investment in the project, with a corresponding increase in its ownership percentage in PEP. Sunoco Logistics maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP will be reflected as a consolidated subsidiary of Sunoco Logistics. ExxonMobil Corp.’s interest will be reflected as noncontrolling interest in Sunoco Logistics’ consolidated balance sheet.
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On August 2, 2016, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a
60%
membership interest and Sunoco Logistics indirectly owns a
40%
membership interest, agreed to sell a
49%
interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for
$2.00 billion
in cash. This transaction closed in February 2017. Bakken Pipeline Investments LLC indirectly owns a
75%
interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”). The remaining
25%
of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP will continue to consolidate Dakota Access and ETCO subsequent to this transaction.
Upon closing, ETP and Sunoco Logistics collectively own a
38.25%
interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the "Bakken Pipeline"), and MarEn Bakken Company owns
36.75%
and Phillips 66 owns
25.00%
in the Bakken Pipeline.
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In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The
$2.50 billion
credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects. As of
December 31, 2016
,
$1.10 billion
was outstanding under this credit facility.
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In March 2016, ETP contributed to Sunoco LP its remaining
68.42%
interest in Sunoco, LLC and
100%
interest in the legacy Sunoco, Inc. retail business for
$2.23 billion
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Sunoco LP paid
$2.20 billion
in cash, including a working capital adjustment and issued
5.7 million
Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of
$1.29 billion
and intangible assets of
$294 million
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The results of Sunoco, LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.
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In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66 Partners LP, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a
30%
interest in the entity and Sunoco Logistics is the operator of the system.
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In February 2017, ETP announced that the Federal Energy Regulatory Commission (“FERC”) approved Rover Pipeline LLC’s (“Rover”) application to construct and operate the Rover Pipeline project, allowing Rover to move forward with its targeted in-service goals of July 2017 for Phase I and November 2017 for Phase II.
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On February 8, 2017, ETP announced that Dakota Access, LLC had received an easement from the U.S. Army Corps of Engineers (“Army Corps”) to construct a pipeline across land owned by the Army Corps on both sides of Lake Oahe in North Dakota. With the receipt of the easement, ETP expects to commence commercial operations on the Dakota Access Pipeline and the adjoining Energy Transfer Crude Oil Pipeline (collectively, the “Bakken Pipeline”) in the second quarter of 2017. In addition, the previously announced project financing for the Bakken Pipeline and the sale of a 36.75% interest in the Bakken Pipeline were completed in February 2017.
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In January 2017, the previously announced Comanche Trail Pipeline, which transports natural gas from the Permian Basin to Mexico, was placed into service.
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We own an
equity method investment in limited partnership units of Sunoco LP consisting of
43.5 million
units, representing
44.3%
of Sunoco LP’s total outstanding common units
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Our wholly-owned subsidiary, Sunoco, Inc., owns an approximate
33%
non-operating interest in PES, a refining joint venture with The Carlyle Group, L.P. (“The Carlyle Group”), which owns a refinery in Philadelphia.
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We conduct 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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We own all of the outstanding equity interests of a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.
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We own 100% of the membership interests of Energy Transfer Group, L.L.C. (“ETG”), which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”). ETT provides compression services to customers engaged in the transportation of natural gas, including our other segments.
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We own a
40%
interest in the parent of LCL, which is developing a LNG liquefaction project, as described further under “Asset Overview – All Other” below.
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We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.
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We 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 Coal Handling, which owns and operates end-user coal handling facilities.
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We also own PEI Power Corp. 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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2,780
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5.2
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11.2
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Oasis Pipeline
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100
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%
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750
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2.3
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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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East Texas Pipeline
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100
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%
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460
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2.4
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—
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RIGS Haynesville Partnership Co.
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49.99
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%
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450
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2.1
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—
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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 Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.
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The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 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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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 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 and Agua Dulce, as well as our Bammel storage facility.
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•
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The East Texas Pipeline connects three treating facilities, one of which we own, with our Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline
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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. The Partnership owns a
49.99%
general partner interest in RIGS.
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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 Pipeline
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50
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%
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5,325
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3.1
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—
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Transwestern Pipeline
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100
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%
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2,600
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2.1
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—
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Panhandle Eastern Pipe Line
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100
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%
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6,000
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2.8
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83.9
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Trunkline Gas Pipeline
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100
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%
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2,000
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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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195
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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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1,000
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2.0
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|
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—
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Midcontinent Express Pipeline
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50
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%
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500
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1.8
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—
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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
|
|
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—
|
|
•
|
The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of
3.1 Bcf/d
and approximately
5,325
miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains over 81 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, industrials and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture with KMI.
|
•
|
The Transwestern Pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: 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. Natural gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
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•
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The 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.
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•
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The Trunkline Gas Pipeline’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.
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•
|
The Tiger Pipeline is an approximately
195
-mile interstate natural gas pipeline with bi-directional capabilities, that connects to our dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.
|
•
|
The Fayetteville Express Pipeline is an approximately
185
-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.
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•
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The Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.
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•
|
The Midcontinent Express Pipeline is an approximately
500
-mile interstate pipeline stretching from southeast Oklahoma through northeast Texas, 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.
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•
|
Gulf States owns a
10
-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
|
Description of Assets
|
|
Net Gas Processing Capacity
(MMcf/d)
|
|
Net Gas Treating Capacity
(MMcf/d)
|
||
South Texas Region:
|
|
|
|
|
||
Southeast Texas System
|
|
410
|
|
|
510
|
|
Eagle Ford System
|
|
1,920
|
|
|
930
|
|
Ark-La-Tex Region
|
|
1,025
|
|
|
1,186
|
|
North Central Texas Region
|
|
740
|
|
|
1,120
|
|
Permian Region
|
|
1,743
|
|
|
1,580
|
|
Mid-Continent Region
|
|
885
|
|
|
20
|
|
Eastern Region
|
|
—
|
|
|
70
|
|
•
|
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 East Texas Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plant (La Grange and Alamo) with aggregate capacity of
410 MMcf/d
and natural gas treating facilities with aggregate capacity of
510 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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•
|
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
1,920 MMcf/d
and one natural gas treating facility with capacity of
930 MMcf/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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•
|
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
1,186 MMcf/d
.
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•
|
Our PennTex Midstream System is primarily located in Lincoln Parish, Louisiana, and consists of the Lincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to our processing plants and third-party processing capacity; a 15-mile 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 a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from our processing plants.
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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, and an interstate NGL pipeline. Collectively, the eight natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada and Brookeland) have an aggregate capacity of
1,025 MMcf/d
.
|
Description of Assets
|
|
Miles of Liquids Pipeline
|
|
Pipeline Throughput Capacity
(Bbls/d)
|
|
NGL Fractionation / Processing Capacity
(Bbls/d)
|
|
Working Storage Capacity
(Bbls)
|
||||
Liquids Pipelines:
|
|
|
|
|
|
|
|
|
||||
Lone Star Express
|
|
532
|
|
|
507,000
|
|
|
—
|
|
|
—
|
|
West Texas Gateway Pipeline
|
|
570
|
|
|
240,000
|
|
|
—
|
|
|
—
|
|
Other NGL Pipelines
|
|
356
|
|
|
691,000
|
|
|
—
|
|
|
—
|
|
Liquids Fractionation and Services Facilities:
|
|
|
|
|
|
|
|
|
||||
Mont Belvieu Facilities
|
|
185
|
|
|
42,000
|
|
|
520,000
|
|
|
50,000,000
|
|
Sea Robin Processing Plant
1
|
|
—
|
|
|
—
|
|
|
26,000
|
|
|
—
|
|
Refinery Services
1
|
|
100
|
|
|
—
|
|
|
25,000
|
|
|
—
|
|
Hattiesburg Storage Facilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,000,000
|
|
(1)
|
Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of
850 MMcf/d
and
54 MMcf/d
, respectively.
|
•
|
The Lone Star Express System is an intrastate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
|
•
|
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.
|
•
|
Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375,000 Bbls/d, the 45-mile Freedom pipeline with a capacity of 56,000 Bbls/d, the 15-mile Spirit pipeline with a capacity of 20,000 Bbls/d, the
82-mile
Rio Bravo crude oil pipeline with a capacity of 100,000 Bbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140,000 Bbls/d.
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•
|
Our Mont Belvieu storage facility is an integrated liquids storage facility with over
50 million Bbls
of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
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•
|
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant, which is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.
|
•
|
Refinery Services consists of a refinery off-gas processing and O-grade NGL fractionation complex located along the Mississippi River refinery corridor in southern Louisiana that cryogenically processes refinery off-gas and fractionates the O-grade NGL stream into its higher value components. The O-grade fractionator, located in Geismar, Louisiana, is connected by approximately
100
miles of pipeline to the Chalmette processing plant, which has a processing capacity of
54 MMcf/d
.
|
•
|
The Hattiesburg storage facility is an integrated liquids storage facility with approximately
3 million Bbls
of salt dome capacity, providing 100% fee-based cash flows.
|
•
|
Southwest United States Pipelines.
The Southwest pipelines include crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma. This includes the Permian Express 2 pipeline project which provides takeaway capacity from the Permian Basin, with origins in multiple locations in Western Texas: Midland, Garden City and Colorado City. Sunoco Logistics’ fourth quarter 2016 acquisition of a West Texas crude oil system from Vitol Inc. and the remaining ownership interest in PET facilitates connection of its Permian Express 2 pipeline to terminal assets in Midland and Garden City, Texas.
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•
|
Midwest United States Pipelines.
Sunoco Logistics owns a controlling financial interest in 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.
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•
|
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, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 26 million barrels in approximately 150 above ground storage tanks with individual capacities of up to 660,000 Bbls.
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•
|
purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;
|
•
|
storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);
|
•
|
buying and selling crude oil of different grades, at different locations in order to maximize value;
|
•
|
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
|
•
|
marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
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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, will expand the total takeaway capacity to 345,000 Bbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the third quarter of 2017.
|
•
|
The Mariner South pipeline is part of a joint project with Lone Star to deliver export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to Sunoco Logistics’ marine terminal in Nederland, Texas. The pipeline has a capacity of approximately 200,000 Bbls/d and can be scaled depending on shipper interest.
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•
|
The Mariner West pipeline provides transportation of ethane products from the Marcellus shale processing and fractionating areas in Houston, Texas, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter 2013, with capacity to transport approximately 50,000 Bbls/d of NGLs and other products.
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•
|
Nederland.
In addition to crude oil activities, the Nederland terminal also provides approximately 1 million barrels 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 delivered via ship.
|
•
|
Marcus Hook Industrial Complex.
In 2013, Sunoco Logistics acquired Sunoco, Inc.’s Marcus Hook Industrial Complex. The acquisition included terminalling and storage assets, with a capacity of approximately 3 million barrels of NGL storage capacity in underground caverns, and related commercial agreements. The facility can receive NGLs via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for the Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.
|
•
|
Inkster.
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million barrels of NGLs. Sunoco Logistics uses 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.
|
•
|
Refined Products.
Sunoco Logistics has approximately 40 refined products terminals with an aggregate storage capacity of approximately 8 million barrels 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.
|
•
|
Eagle Point.
In additional to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million barrels, and provides customers with access to the facility via barge and pipeline. The terminal can deliver via 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.
|
•
|
Marcus Hook Industrial Complex.
The Marcus Hook Industrial Complex can receive refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. The terminal has a total active refined products storage capacity of approximately 2 million barrels.
|
•
|
Marcus Hook Tank Farm.
The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million barrels of refined products storage. The tank farm historically served Sunoco Inc.'s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.'s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on Sunoco Logistics’ refined products pipelines.
|
•
|
Sunoco LP.
We have an
equity method investment in limited partnership units of Sunoco LP consisting of
43.5 million
units, representing
44.3%
of Sunoco LP’s total outstanding common units
.
|
•
|
PES.
We have
a non-controlling interest in PES, comprising
33%
of PES’ outstanding common units.
|
•
|
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, crude oil and products transported in our pipelines and gathering systems;
|
•
|
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 products;
|
•
|
the relationship between natural gas, NGL and crude oil prices;
|
•
|
the amount of cash distributions we receive with respect to the Sunoco LP, PennTex and Sunoco Logistics common units that we or our subsidiaries own;
|
•
|
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.
|
•
|
the current proportionate ownership interest of our Unitholders in us 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 the Common Units or partnership securities may decline.
|
•
|
Unitholders’ current proportionate ownership interest in the respective partnerships 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 the respective partnerships 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 Unitholders and our General Partner for any one or more of the next four calendar quarters; or
|
•
|
to comply with applicable law or any of our loan or other agreements.
|
•
|
economic downturns;
|
•
|
deteriorating capital market conditions;
|
•
|
declining market prices for natural gas, NGLs and other commodities;
|
•
|
terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
|
•
|
the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
|
•
|
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 ETE, in resolving conflicts of interest, thereby limiting its fiduciary duties to us.
|
•
|
Our General Partner’s affiliates, including ETE, 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 ETE.
|
•
|
Neither our partnership agreement nor any other agreement requires ETE or its affiliates to pursue a business strategy that favors us. The directors and officers of the general partners of ETE 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 ETE who provide advice to us also may devote significant time to the businesses of ETE 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;
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
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;
|
•
|
changes in Sunoco Logistics’ business, operations and prospects;
|
•
|
changes in market assessments of Sunoco Logistics’ business, operations and prospects;
|
•
|
interest rates, general market, industry and economic conditions and other factors generally affecting the price of Sunoco Logistics common units; and
|
•
|
federal, state and local legislation, governmental regulation and legal developments in the businesses in which Sunoco Logistics operates.
|
•
|
liability for damages under the terms and conditions of the merger agreement;
|
•
|
negative reactions from the financial markets, including declines in the price of Sunoco Logistics’ and ETP’s common units due to the fact that current prices may reflect a market assumption that the merger will be completed; and
|
•
|
the attention of Sunoco Logistics’ and ETP’s management will have been diverted to the merger rather than its own operations and pursuit of other opportunities that could have been beneficial to Sunoco Logistics or ETP.
|
|
Price Range
|
|
Cash Distribution
(1)
|
||||||||
|
High
|
|
Low
|
|
|||||||
Fiscal Year 2016
|
|
|
|
|
|
||||||
Fourth Quarter
|
$
|
40.70
|
|
|
$
|
32.67
|
|
|
$
|
1.0550
|
|
Third Quarter
|
43.50
|
|
|
35.02
|
|
|
1.0550
|
|
|||
Second Quarter
|
41.29
|
|
|
29.86
|
|
|
1.0550
|
|
|||
First Quarter
|
35.39
|
|
|
18.62
|
|
|
1.0550
|
|
|||
|
|
|
|
|
|
||||||
Fiscal Year 2015
|
|
|
|
|
|
||||||
Fourth Quarter
|
$
|
47.53
|
|
|
$
|
27.44
|
|
|
$
|
1.0550
|
|
Third Quarter
|
54.64
|
|
|
36.84
|
|
|
1.0550
|
|
|||
Second Quarter
|
59.37
|
|
|
51.73
|
|
|
1.0350
|
|
|||
First Quarter
|
66.58
|
|
|
53.25
|
|
|
1.0150
|
|
(1)
|
Distributions are shown in the quarter with respect to which they relate. Please see “Cash Distribution Policy” below for a discussion of our policy regarding the payment of distributions.
|
•
|
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;
|
•
|
comply with applicable law and/or debt instrument or other agreement (including reserves for future capital expenditures and for our future capital needs); or
|
•
|
provide funds for distributions to Unitholders and our General Partner in respect of any one or more of the next four quarters.
|
•
|
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.
|
•
|
our cash balance on the closing date of our initial public offering in 1996; plus
|
•
|
$10 million (as described below); plus
|
•
|
all of our cash receipts since the closing of our initial public offering, excluding cash from interim capital transactions such as borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus
|
•
|
our working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less
|
•
|
all of our operating expenditures after the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less
|
•
|
the amount of our cash reserves that our General Partner deems necessary or advisable to provide funds for future operating expenditures.
|
•
|
borrowings other than working capital borrowings;
|
•
|
sales of our debt and equity securities; and
|
•
|
sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.
|
•
|
First
, 100% to all Common Unitholders, Class E Unitholders, Class G Unitholders, Class K Unitholders and the general partner, in accordance with their percentage interests, until each Common Unit has received $0.25 per unit for such quarter (the “minimum quarterly distribution”);
|
•
|
Second
, 100% to all Common Unitholders, Class E Unitholders, Class G Unitholders, Class K Unitholders and the general partner, in accordance with their respective percentage interests, until each Common Unit has received $0.275 per unit for such quarter (the “first target distribution”);
|
•
|
Third
, (i) to the general partner in accordance with its percentage interest, (ii) 13% to the holders of the IDRs, pro rata, and (iii) to all Common Unitholders, Class E Unitholders, Class G Unitholders and Class K Unitholders, pro rata, a percentage equal to 100% less the percentages applicable to the general partner and holders of the IDRs, until each Common Unit has received $0.3175 per unit for such quarter (the “second target distribution”);
|
•
|
Fourth
, (i) to the general partner in accordance with its percentage interest, (ii) 23% to the holders of the IDRs, pro rata, and (iii) to all Common Unitholders, Class E Unitholders, Class G Unitholders and Class K Unitholders, pro rata, a percentage equal to 100% less the percentages applicable to the general partner and holders of the IDRs, until each Common Unit has received $0.4125 per unit for such quarter (the “third target distribution”); and
|
•
|
Fifth
, thereafter, (i) to the general partner in accordance with its percentage interest, (ii) 48% to the holder of the IDRs, pro rata, and (iii) to all Common Unitholders, Class E Unitholders, Class G Unitholders and Class K Unitholders, pro rata, a percentage equal to 100% less the percentages applicable to the general partner and holders of the IDRs.
|
•
|
First
, to all of our Unitholders and to our General Partner, in accordance with their percentage interests, until we distribute for each Common Unit, an amount of available cash from capital surplus equal to our initial public offering price; and
|
•
|
Thereafter
, we will make all distributions of Available Cash from capital surplus as if they were from operating surplus.
|
|
|
Total Year
|
||
2017
|
|
$
|
626
|
|
2018
|
|
138
|
|
|
2019
|
|
128
|
|
|
Each year beyond 2019
|
|
33
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
21,827
|
|
|
$
|
34,292
|
|
|
$
|
55,475
|
|
|
$
|
48,335
|
|
|
$
|
16,964
|
|
Operating income
|
1,802
|
|
|
2,259
|
|
|
2,443
|
|
|
1,619
|
|
|
1,425
|
|
|||||
Income from continuing operations
|
624
|
|
|
1,521
|
|
|
1,235
|
|
|
713
|
|
|
1,754
|
|
|||||
Basic income (loss) from continuing operations per Common Unit
|
(2.06
|
)
|
|
(0.09
|
)
|
|
1.58
|
|
|
(0.23
|
)
|
|
4.93
|
|
|||||
Diluted income (loss) from continuing operations per Common Unit
|
(2.06
|
)
|
|
(0.10
|
)
|
|
1.58
|
|
|
(0.23
|
)
|
|
4.91
|
|
|||||
Cash distributions per unit
|
4.22
|
|
|
4.16
|
|
|
3.86
|
|
|
3.61
|
|
|
3.58
|
|
|||||
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
70,191
|
|
|
65,173
|
|
|
62,518
|
|
|
49,900
|
|
|
48,394
|
|
|||||
Long-term debt, less current maturities
|
31,741
|
|
|
28,553
|
|
|
24,831
|
|
|
19,761
|
|
|
17,599
|
|
|||||
Total equity
|
26,527
|
|
|
27,031
|
|
|
25,311
|
|
|
18,694
|
|
|
19,982
|
|
|||||
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
||||||||||
Maintenance (accrual basis)
|
368
|
|
|
485
|
|
|
444
|
|
|
391
|
|
|
347
|
|
|||||
Growth (accrual basis)
|
5,442
|
|
|
7,682
|
|
|
5,050
|
|
|
2,936
|
|
|
3,186
|
|
|||||
Cash paid for acquisitions
|
1,227
|
|
|
804
|
|
|
2,367
|
|
|
1,737
|
|
|
1,364
|
|
•
|
Natural gas operations, including the following:
|
•
|
natural gas midstream and intrastate transportation and storage; and
|
•
|
interstate natural gas transportation and storage through ET Interstate and Panhandle. ET Interstate is the parent company of Transwestern, ETC FEP, ETC Tiger, CrossCountry, ETC MEP and ET Rover. Panhandle is the parent company of the Trunkline and Sea Robin transmission systems.
|
•
|
Liquids operations, including NGL transportation, storage and fractionation services.
|
•
|
Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities through Sunoco Logistics.
|
•
|
Intrastate transportation and storage – Revenue is principally generated from fees charged to customers to reserve firm capacity on or move gas through our pipelines on an interruptible basis. Our interruptible or short-term business is generally impacted by basis differentials between delivery points on our system and the price of natural gas. The basis differentials that primarily impact our interruptible business are primarily among receipt points between West Texas to East Texas or segments thereof. When narrow or flat spreads exist, our open capacity may be underutilized and go unsold. Conversely, when basis differentials widen, our interruptible volumes and fees generally increase. The fee structure normally consists of a monetary fee and fuel retention. Excess fuel retained after consumption, if any, is typically sold at market prices. In addition to transport fees, we
|
•
|
Interstate transportation and storage – The majority of our interstate transportation and storage revenues are generated through firm reservation charges that are based on the amount of firm capacity reserved for our firm shippers regardless of usage. Tiger, FEP, Transwestern, Panhandle, MEP and Gulf States shippers have made long-term commitments to pay reservation charges for the firm capacity reserved for their use. In addition to reservation revenues, additional revenue sources include interruptible transportation charges as well as usage rates and overrun rates paid by firm shippers based on their actual capacity usage.
|
•
|
Midstream – Revenue is principally dependent upon the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipelines as well as the level of natural gas and NGL prices.
|
•
|
Liquids transportation and services – Liquids transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and competitive with regional regulated pipelines.
|
•
|
Investment in Sunoco Logistics – Revenues are generated by charging tariffs for transporting crude oil, NGLs and refined products through Sunoco Logistics’ pipelines as well as by charging fees for terminalling services for crude oil, NGLs and refined products at its facilities. Revenues are also generated by acquiring and marketing crude oil, NGLs and refined products. Generally, crude oil, NGLs and refined products purchases are entered into in contemplation of or simultaneously with corresponding sale transactions involving physical deliveries, which enables us to secure a profit on the transaction at the time of purchase.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
613
|
|
|
$
|
543
|
|
|
$
|
70
|
|
Interstate transportation and storage
|
1,117
|
|
|
1,155
|
|
|
(38
|
)
|
|||
Midstream
|
1,133
|
|
|
1,237
|
|
|
(104
|
)
|
|||
Liquids transportation and services
|
968
|
|
|
744
|
|
|
224
|
|
|||
Investment in Sunoco Logistics
|
1,233
|
|
|
1,153
|
|
|
80
|
|
|||
All other
|
541
|
|
|
882
|
|
|
(341
|
)
|
|||
Total
|
5,605
|
|
|
5,714
|
|
|
(109
|
)
|
|||
Depreciation, depletion and amortization
|
(1,986
|
)
|
|
(1,929
|
)
|
|
(57
|
)
|
|||
Interest expense, net
|
(1,317
|
)
|
|
(1,291
|
)
|
|
(26
|
)
|
|||
Gains on acquisitions
|
83
|
|
|
—
|
|
|
83
|
|
|||
Impairment losses
|
(813
|
)
|
|
(339
|
)
|
|
(474
|
)
|
|||
Losses on interest rate derivatives
|
(12
|
)
|
|
(18
|
)
|
|
6
|
|
|||
Non-cash unit-based compensation expense
|
(80
|
)
|
|
(79
|
)
|
|
(1
|
)
|
|||
Unrealized losses on commodity risk management activities
|
(131
|
)
|
|
(65
|
)
|
|
(66
|
)
|
|||
Inventory valuation adjustments
|
170
|
|
|
(104
|
)
|
|
274
|
|
|||
Losses on extinguishments of debt
|
—
|
|
|
(43
|
)
|
|
43
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
(946
|
)
|
|
(937
|
)
|
|
(9
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
59
|
|
|
469
|
|
|
(410
|
)
|
|||
Impairment of investment in an unconsolidated affiliate
|
(308
|
)
|
|
—
|
|
|
(308
|
)
|
|||
Other, net
|
114
|
|
|
20
|
|
|
94
|
|
|||
Income before income tax benefit
|
438
|
|
|
1,398
|
|
|
(960
|
)
|
|||
Income tax benefit
|
186
|
|
|
123
|
|
|
63
|
|
|||
Net income
|
$
|
624
|
|
|
$
|
1,521
|
|
|
$
|
(897
|
)
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Equity in earnings (losses) of unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
102
|
|
|
$
|
97
|
|
|
$
|
5
|
|
FEP
|
51
|
|
|
55
|
|
|
(4
|
)
|
|||
PES
|
(26
|
)
|
|
52
|
|
|
(78
|
)
|
|||
MEP
|
40
|
|
|
45
|
|
|
(5
|
)
|
|||
HPC
|
31
|
|
|
32
|
|
|
(1
|
)
|
|||
AmeriGas
|
14
|
|
|
(3
|
)
|
|
17
|
|
|||
Sunoco, LLC
|
—
|
|
|
(10
|
)
|
|
10
|
|
|||
Sunoco LP
(1)
|
(211
|
)
|
|
202
|
|
|
(413
|
)
|
|||
Other
|
58
|
|
|
(1
|
)
|
|
59
|
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
59
|
|
|
$
|
469
|
|
|
$
|
(410
|
)
|
|
|
|
|
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
(2)
:
|
|
|
|
|
|
||||||
Citrus
|
$
|
329
|
|
|
$
|
315
|
|
|
$
|
14
|
|
FEP
|
75
|
|
|
75
|
|
|
—
|
|
|||
PES
|
10
|
|
|
86
|
|
|
(76
|
)
|
|||
MEP
|
90
|
|
|
96
|
|
|
(6
|
)
|
|||
HPC
|
61
|
|
|
61
|
|
|
—
|
|
|||
Sunoco, LLC
|
—
|
|
|
91
|
|
|
(91
|
)
|
|||
Sunoco LP
|
271
|
|
|
137
|
|
|
134
|
|
|||
Other
|
110
|
|
|
76
|
|
|
34
|
|
|||
Total Adjusted EBITDA related to unconsolidated affiliates
|
$
|
946
|
|
|
$
|
937
|
|
|
$
|
9
|
|
|
|
|
|
|
|
||||||
Distributions received from unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
144
|
|
|
$
|
182
|
|
|
$
|
(38
|
)
|
FEP
|
65
|
|
|
69
|
|
|
(4
|
)
|
|||
PES
|
—
|
|
|
78
|
|
|
(78
|
)
|
|||
MEP
|
74
|
|
|
80
|
|
|
(6
|
)
|
|||
HPC
|
51
|
|
|
52
|
|
|
(1
|
)
|
|||
AmeriGas
|
12
|
|
|
11
|
|
|
1
|
|
|||
Sunoco LP
|
138
|
|
|
39
|
|
|
99
|
|
|||
Other
|
57
|
|
|
53
|
|
|
4
|
|
|||
Total distributions received from unconsolidated affiliates
|
$
|
541
|
|
|
$
|
564
|
|
|
$
|
(23
|
)
|
(1)
|
For the year ended
December 31, 2016
, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $277 million.
|
(2)
|
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
|
•
|
Gross 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 gross margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
|
•
|
Non-cash compensation expense
. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
|
•
|
Adjusted EBITDA related to unconsolidated affiliates
. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Natural gas transported (MMBtu/d)
|
8,257,611
|
|
|
8,426,818
|
|
|
(169,207
|
)
|
|||
Revenues
|
$
|
2,613
|
|
|
$
|
2,250
|
|
|
$
|
363
|
|
Cost of products sold
|
1,897
|
|
|
1,554
|
|
|
343
|
|
|||
Gross margin
|
716
|
|
|
696
|
|
|
20
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
19
|
|
|
(26
|
)
|
|
45
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(162
|
)
|
|
(163
|
)
|
|
1
|
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(22
|
)
|
|
(25
|
)
|
|
3
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
61
|
|
|
61
|
|
|
—
|
|
|||
Other
|
1
|
|
|
—
|
|
|
1
|
|
|||
Segment Adjusted EBITDA
|
$
|
613
|
|
|
$
|
543
|
|
|
$
|
70
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Transportation fees
|
$
|
505
|
|
|
$
|
502
|
|
|
$
|
3
|
|
Natural gas sales and other
|
113
|
|
|
96
|
|
|
17
|
|
|||
Retained fuel revenues
|
48
|
|
|
57
|
|
|
(9
|
)
|
|||
Storage margin, including fees
|
50
|
|
|
41
|
|
|
9
|
|
|||
Total gross margin
|
$
|
716
|
|
|
$
|
696
|
|
|
$
|
20
|
|
•
|
an increase of
$3 million
in transportation fees, despite lower throughput volumes, due to fees from renegotiated and newly initiated fixed fee contracts primarily on our Houston Pipeline system;
|
•
|
an increase of $34 million in natural gas sales (excluding changes in unrealized losses of $17 million) primarily due to higher realized gains from the buying and selling of gas along our system;
|
•
|
a decrease of $9 million from the sale of retained fuel, primarily due to lower market prices and lower volumes. The average spot price at the Houston Ship Channel location decreased 5% for the year ended December 31, 2016 compared to the prior year;
|
•
|
an increase of $37 million in storage margin (excluding net changes in unrealized amounts of $28 million related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below; and
|
•
|
a decrease of
$3 million
in general and administrative expenses primarily due to lower legal fees and insurance costs, as well as allocations between segments.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Withdrawals from storage natural gas inventory (MMBtu)
|
38,905,000
|
|
|
15,782,500
|
|
|
23,122,500
|
|
|||
Realized margin on natural gas inventory transactions
|
$
|
36
|
|
|
$
|
(2
|
)
|
|
$
|
38
|
|
Fair value inventory adjustments
|
76
|
|
|
4
|
|
|
72
|
|
|||
Unrealized (gains) losses on derivatives
|
(87
|
)
|
|
12
|
|
|
(99
|
)
|
|||
Margin recognized on natural gas inventory, including related derivatives
|
25
|
|
|
14
|
|
|
11
|
|
|||
Revenues from fee-based storage
|
25
|
|
|
27
|
|
|
(2
|
)
|
|||
Total storage margin
|
$
|
50
|
|
|
$
|
41
|
|
|
$
|
9
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Natural gas transported (MMBtu/d)
|
5,475,948
|
|
|
6,074,282
|
|
|
(598,334
|
)
|
|||
Natural gas sold (MMBtu/d)
|
18,842
|
|
|
17,340
|
|
|
1,502
|
|
|||
Revenues
|
$
|
969
|
|
|
$
|
1,025
|
|
|
$
|
(56
|
)
|
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
|
(302
|
)
|
|
(304
|
)
|
|
2
|
|
|||
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
|
(47
|
)
|
|
(52
|
)
|
|
5
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
494
|
|
|
486
|
|
|
8
|
|
|||
Other
|
3
|
|
|
—
|
|
|
3
|
|
|||
Segment Adjusted EBITDA
|
$
|
1,117
|
|
|
$
|
1,155
|
|
|
$
|
(38
|
)
|
•
|
a decrease of
$26 million
in revenues due to contract restructuring on the Tiger pipeline, a decrease of
$17 million
due to lower reservation revenues on the Panhandle and Trunkline pipelines from capacity sold at lower rates and lower sales of capacity in the Phoenix and San Juan areas on the Transwestern pipeline, a decrease of
$14 million
due to the transfer of one of the Trunkline pipelines which was repurposed from natural gas service to crude oil service, a decrease of
$11 million
due to the expiration of a transportation rate schedule on the Transwestern pipeline, and a decrease of
$10 million
on the Sea Robin pipeline due to declines in production and third-party maintenance. These decreases were partially offset by higher reservation revenues on the Transwestern pipeline of
$18 million
, primarily from a growth project, and higher parking revenues of
$9 million
, primarily on the Panhandle and Trunkline pipelines; partially offset by
|
•
|
an increase of
$8 million
in Adjusted EBITDA related to unconsolidated affiliates primarily due to higher margins from sales of additional capacity on Citrus of $6 million and lower operating expenses of $5 million, offset by lower margins on the Midcontinent Express pipeline of $4 million due to a customer bankruptcy;
|
•
|
a decrease of
$2 million
in operating expenses primarily due to lower maintenance project costs of $5 million and lower allocated costs of $3 million. These decreases were partially offset by an increase of $7 million in ad valorem tax expense due to higher current year assessments of $2 million and a prior period credit and settlement of ad valorem taxes in 2015 of $5 million;
|
•
|
a decrease of
$5 million
in selling, general and administrative expenses primarily due to $5 million in lower allocated costs; and
|
•
|
an increase of
$3 million
in other primarily due to the tax gross-up associated with reimbursable projects on the Transwestern and Panhandle pipelines.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Gathered volumes (MMBtu/d)
|
9,813,660
|
|
|
9,981,212
|
|
|
(167,552
|
)
|
|||
NGLs produced (Bbls/d)
|
437,730
|
|
|
406,149
|
|
|
31,581
|
|
|||
Equity NGLs (Bbls/d)
|
31,131
|
|
|
28,493
|
|
|
2,638
|
|
|||
Revenues
|
$
|
5,179
|
|
|
$
|
5,056
|
|
|
$
|
123
|
|
Cost of products sold
|
3,381
|
|
|
3,264
|
|
|
117
|
|
|||
Gross margin
|
1,798
|
|
|
1,792
|
|
|
6
|
|
|||
Unrealized losses on commodity risk management activities
|
15
|
|
|
82
|
|
|
(67
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(621
|
)
|
|
(616
|
)
|
|
(5
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(84
|
)
|
|
(44
|
)
|
|
(40
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
24
|
|
|
20
|
|
|
4
|
|
|||
Other
|
1
|
|
|
3
|
|
|
(2
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
1,133
|
|
|
$
|
1,237
|
|
|
$
|
(104
|
)
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Gathering and processing fee-based revenues
|
$
|
1,554
|
|
|
$
|
1,570
|
|
|
$
|
(16
|
)
|
Non fee-based contracts and processing
|
244
|
|
|
222
|
|
|
22
|
|
|||
Total gross margin
|
$
|
1,798
|
|
|
$
|
1,792
|
|
|
$
|
6
|
|
•
|
a decrease of $16 million in fee-based margin due to volume declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, partially offset by increased gathering and processing volumes in the Permian region and the impact of recent acquisitions, including PennTex and the King Ranch assets;
|
•
|
an increase of
$40 million
in general and administrative expenses primarily due to costs associated with the acquisition of PennTex and changes in capitalized overhead and accruals;
|
•
|
an increase of
$5 million
in operating expenses primarily due to the King Ranch acquisition in the second quarter of 2015 and assets recently placed in service in the Permian and Eagle Ford regions; and
|
•
|
a decrease of $92 million (excluding unrealized gains of $67 million) in non fee-based margin due to lower benefit from settled derivatives used to hedge commodity margins; partially offset by
|
•
|
an increase of $44 million in non fee-based margin due to volume increases in the Permian region, partially offset by volume declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions; and
|
•
|
an increase of $3 million in non fee-based margin due to higher crude oil and NGL prices, partially offset by lower natural gas prices.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Liquids transportation volumes (Bbls/d)
|
627,164
|
|
|
501,666
|
|
|
125,498
|
|
|||
NGL fractionation volumes (Bbls/d)
|
361,017
|
|
|
235,800
|
|
|
125,217
|
|
|||
Revenues
|
$
|
4,797
|
|
|
$
|
3,496
|
|
|
$
|
1,301
|
|
Cost of products sold
|
3,673
|
|
|
2,597
|
|
|
1,076
|
|
|||
Gross margin
|
1,124
|
|
|
899
|
|
|
225
|
|
|||
Unrealized losses on commodity risk management activities
|
32
|
|
|
6
|
|
|
26
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(172
|
)
|
|
(152
|
)
|
|
(20
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(18
|
)
|
|
(16
|
)
|
|
(2
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
1
|
|
|
7
|
|
|
(6
|
)
|
|||
Other
|
1
|
|
|
—
|
|
|
1
|
|
|||
Segment Adjusted EBITDA
|
$
|
968
|
|
|
$
|
744
|
|
|
$
|
224
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Transportation margin
|
$
|
500
|
|
|
$
|
394
|
|
|
$
|
106
|
|
Processing and fractionation margin
|
404
|
|
|
297
|
|
|
107
|
|
|||
Storage margin
|
208
|
|
|
172
|
|
|
36
|
|
|||
Other margin
|
12
|
|
|
36
|
|
|
(24
|
)
|
|||
Total gross margin
|
$
|
1,124
|
|
|
$
|
899
|
|
|
$
|
225
|
|
•
|
an increase of
$36 million
in storage margin primarily due to increased volumes from our Mont Belvieu fractionators. Throughput volumes, on which we earn a fee in our storage assets, increased 34% resulting in an increase of $18 million year over year. We also realized an increase of $8 million due to increased demand for our leased storage capacity as a result of more favorable market conditions. Finally, we realized increased terminal fees and pipeline lease fees of $8 million, as well as increased blending gains of $2 million resulting from higher volumes during the 2016 period;
|
•
|
an increase of
$106 million
in transportation fees due to higher NGL and crude transport volumes. NGL transport volumes were higher from all producing regions, with the Permian region being the most significant among them. Higher NGL volumes transported resulted in an $80 million increase in transport fees. We realized increases of $20 million in crude transport fees, primarily resulting from placing in-service the first phase of the Bayou Bridge pipeline in April 2016, and from placing crude gathering assets in West Texas in-service during the 2016 period; and
|
•
|
an increase of
$107 million
in processing and fractionation margin (excluding an increase in unrealized losses of $11 million) primarily due to higher NGL volumes from all producing regions, as detailed in our transport fees explanation above. We placed approximately 118,000bbls/d of fractionation capacity in-service in 2016, allowing our Mont Belvieu fractionators to handle the significant increase in volumes from year to year. Additional barrels fractionated and an associated increase in blending gains at our fractionators resulted in a margin increase of $101 million. We delivered approximately 26% more barrels to our Mariner South LPG export terminal in the 2016 period, which resulted in an increase of $22 million in cargo loading fees and blending fees year over year. These gains were offset by an increase in storage fees paid of $2 million, and a decrease in margin from our refinery services segment of $3 million; partially offset by
|
•
|
a decrease of
$24 million
in other margin due to the timing of the withdrawal and sale of NGL component product inventory; and
|
•
|
an increase of
$20 million
in operating expenses primarily due to increased costs associated with our third fractionator at Mont Belvieu and higher ad valorem expenses; partially offset by lower project related expenses.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Revenue
|
$
|
9,151
|
|
|
$
|
10,486
|
|
|
$
|
(1,335
|
)
|
Cost of products sold
|
7,658
|
|
|
9,307
|
|
|
(1,649
|
)
|
|||
Gross margin
|
1,493
|
|
|
1,179
|
|
|
314
|
|
|||
Unrealized losses on commodity risk management activities
|
39
|
|
|
4
|
|
|
35
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(113
|
)
|
|
(158
|
)
|
|
45
|
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(96
|
)
|
|
(92
|
)
|
|
(4
|
)
|
|||
Inventory valuation adjustments
|
(170
|
)
|
|
162
|
|
|
(332
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
80
|
|
|
58
|
|
|
22
|
|
|||
Segment Adjusted EBITDA
|
$
|
1,233
|
|
|
$
|
1,153
|
|
|
$
|
80
|
|
•
|
an increase of $65 million from Sunoco Logistics’ refined products operations, primarily due to improved operating results from Sunoco Logistics’ refined products pipelines of $32 million, which benefited from higher volumes on Sunoco Logistics’ Allegheny Access pipeline, and higher results from Sunoco Logistics’ refined products acquisition and marketing activities of $21 million. Improved contributions from Sunoco Logistics’ refined product joint venture interests of $6 million and higher earnings attributable to Sunoco Logistics’ refined products terminals of $5 million also contributed to the current year improvement; and
|
•
|
an increase of $31 million from Sunoco Logistics’ crude oil operations, primarily due to improved results from Sunoco Logistics’ crude oil pipelines of $155 million which benefited from the expansion capital projects which commenced operations in 2016 and 2015, and the fourth quarter 2016 acquisition from Vitol, including the remaining interest in SunVit. Higher results from Sunoco Logistics’ crude oil terminals of $31 million, largely related to Sunoco Logistics’ Nederland facility, and improved contributions from Sunoco Logistics’ crude oil joint venture interests of $16 million also contributed to the increase. These positive factors were largely offset by a decrease in operating results from Sunoco Logistics’ crude oil acquisition and marketing activities of $166 million, which includes transportation and storage fees related to Sunoco Logistics’ crude oil pipelines and terminal facilities, due to lower crude oil differentials and decreased volumes compared to the prior year; offset by
|
•
|
a decrease of $16 million from Sunoco Logistics’ NGLs operations, primarily attributable to lower operating results from Sunoco Logistics’ NGLs acquisition and marketing activities of $106 million due to lower volumes and margins compared to the prior year. These factors were largely offset by increased volumes and fees from Sunoco Logistics’ Mariner NGLs projects of $90 million, which includes Sunoco Logistics’ NGLs pipelines and Marcus Hook and Nederland facilities.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2016
|
|
2015
|
|
Change
|
||||||
Revenue
|
$
|
3,271
|
|
|
$
|
15,774
|
|
|
$
|
(12,503
|
)
|
Cost of products sold
|
2,942
|
|
|
14,029
|
|
|
(11,087
|
)
|
|||
Gross margin
|
329
|
|
|
1,745
|
|
|
(1,416
|
)
|
|||
Unrealized (gains) losses on commodity risk management activities
|
26
|
|
|
(1
|
)
|
|
27
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(79
|
)
|
|
(896
|
)
|
|
817
|
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(86
|
)
|
|
(254
|
)
|
|
168
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
286
|
|
|
313
|
|
|
(27
|
)
|
|||
Inventory valuation adjustments
|
—
|
|
|
(58
|
)
|
|
58
|
|
|||
Other
|
95
|
|
|
95
|
|
|
—
|
|
|||
Elimination
|
(30
|
)
|
|
(62
|
)
|
|
32
|
|
|||
Segment Adjusted EBITDA
|
$
|
541
|
|
|
$
|
882
|
|
|
$
|
(341
|
)
|
•
|
our
retail marketing operations prior to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016
;
|
•
|
our
equity method investment in limited partnership units of Sunoco LP consisting of
43.5 million
units, representing
44.3%
of Sunoco LP’s total outstanding common units
;
|
•
|
our natural gas marketing and compression operations;
|
•
|
a non-controlling interest in PES, comprising
33%
of PES’ outstanding common units; and
|
•
|
our investment in Coal Handling, an entity that owns and operates end-user coal handling facilities.
|
•
|
a decrease of
$308 million
due to the transfer and contribution of our retail marketing assets to Sunoco LP. The consolidated results of Sunoco LP are reflected in the results for All Other above through June 2015. Effective July 1, 2015, Sunoco LP was deconsolidated, and the results for All Other reflect Adjusted EBITDA related to unconsolidated affiliates for our limited partner interests in Sunoco LP. The impact of the deconsolidation of Sunoco LP reduced gross margin, operating expenses and selling, general and administrative expenses; the impact to Segment Adjusted EBITDA is offset by the incremental Adjusted EBITDA related to unconsolidated affiliates from our equity method investment in Sunoco LP subsequent to the deconsolidation; and
|
•
|
a decrease of
$76 million
in Adjusted EBITDA related to our investment in PES.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
543
|
|
|
$
|
559
|
|
|
$
|
(16
|
)
|
Interstate transportation and storage
|
1,155
|
|
|
1,212
|
|
|
(57
|
)
|
|||
Midstream
|
1,237
|
|
|
1,318
|
|
|
(81
|
)
|
|||
Liquids transportation and services
|
744
|
|
|
591
|
|
|
153
|
|
|||
Investment in Sunoco Logistics
|
1,153
|
|
|
971
|
|
|
182
|
|
|||
All other
|
882
|
|
|
1,059
|
|
|
(177
|
)
|
|||
Total
|
5,714
|
|
|
5,710
|
|
|
4
|
|
|||
Depreciation, depletion and amortization
|
(1,929
|
)
|
|
(1,669
|
)
|
|
(260
|
)
|
|||
Interest expense, net
|
(1,291
|
)
|
|
(1,165
|
)
|
|
(126
|
)
|
|||
Gain on sale of AmeriGas common units
|
—
|
|
|
177
|
|
|
(177
|
)
|
|||
Impairment losses
|
(339
|
)
|
|
(370
|
)
|
|
31
|
|
|||
Losses on interest rate derivatives
|
(18
|
)
|
|
(157
|
)
|
|
139
|
|
|||
Non-cash compensation expense
|
(79
|
)
|
|
(68
|
)
|
|
(11
|
)
|
|||
Unrealized gains (losses) on commodity risk management activities
|
(65
|
)
|
|
112
|
|
|
(177
|
)
|
|||
Inventory valuation adjustments
|
(104
|
)
|
|
(473
|
)
|
|
369
|
|
|||
Losses on extinguishments of debt
|
(43
|
)
|
|
(25
|
)
|
|
(18
|
)
|
|||
Adjusted EBITDA related to discontinued operations
|
—
|
|
|
(27
|
)
|
|
27
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
(937
|
)
|
|
(748
|
)
|
|
(189
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
469
|
|
|
332
|
|
|
137
|
|
|||
Other, net
|
20
|
|
|
(36
|
)
|
|
56
|
|
|||
Income from continuing operations before income tax (expense) benefit
|
1,398
|
|
|
1,593
|
|
|
(195
|
)
|
|||
Income tax (expense) benefit from continuing operations
|
123
|
|
|
(358
|
)
|
|
481
|
|
|||
Income from continuing operations
|
1,521
|
|
|
1,235
|
|
|
286
|
|
|||
Income from discontinued operations
|
—
|
|
|
64
|
|
|
(64
|
)
|
|||
Net income
|
$
|
1,521
|
|
|
$
|
1,299
|
|
|
$
|
222
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Equity in earnings (losses) of unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
97
|
|
|
$
|
96
|
|
|
$
|
1
|
|
FEP
|
55
|
|
|
55
|
|
|
—
|
|
|||
PES
|
52
|
|
|
59
|
|
|
(7
|
)
|
|||
MEP
|
45
|
|
|
45
|
|
|
—
|
|
|||
HPC
|
32
|
|
|
28
|
|
|
4
|
|
|||
AmeriGas
|
(3
|
)
|
|
21
|
|
|
(24
|
)
|
|||
Sunoco, LLC
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
|||
Sunoco LP
|
202
|
|
|
—
|
|
|
202
|
|
|||
Other
|
(1
|
)
|
|
28
|
|
|
(29
|
)
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
469
|
|
|
$
|
332
|
|
|
$
|
137
|
|
|
|
|
|
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
(1)
:
|
|
|
|
|
|
||||||
Citrus
|
$
|
315
|
|
|
$
|
305
|
|
|
$
|
10
|
|
FEP
|
75
|
|
|
75
|
|
|
—
|
|
|||
PES
|
86
|
|
|
86
|
|
|
—
|
|
|||
MEP
|
96
|
|
|
102
|
|
|
(6
|
)
|
|||
HPC
|
61
|
|
|
53
|
|
|
8
|
|
|||
AmeriGas
|
—
|
|
|
56
|
|
|
(56
|
)
|
|||
Sunoco, LLC
|
91
|
|
|
—
|
|
|
91
|
|
|||
Sunoco LP
|
137
|
|
|
—
|
|
|
137
|
|
|||
Other
|
76
|
|
|
71
|
|
|
5
|
|
|||
Total Adjusted EBITDA related to unconsolidated affiliates
|
$
|
937
|
|
|
$
|
748
|
|
|
$
|
189
|
|
|
|
|
|
|
|
||||||
Distributions received from unconsolidated affiliates:
|
|
|
|
|
|
||||||
Citrus
|
$
|
182
|
|
|
$
|
168
|
|
|
$
|
14
|
|
FEP
|
69
|
|
|
70
|
|
|
(1
|
)
|
|||
PES
|
78
|
|
|
—
|
|
|
78
|
|
|||
MEP
|
80
|
|
|
73
|
|
|
7
|
|
|||
HPC
|
52
|
|
|
48
|
|
|
4
|
|
|||
AmeriGas
|
11
|
|
|
28
|
|
|
(17
|
)
|
|||
Sunoco LP
|
39
|
|
|
—
|
|
|
39
|
|
|||
Other
|
53
|
|
|
40
|
|
|
13
|
|
|||
Total distributions received from unconsolidated affiliates
|
$
|
564
|
|
|
$
|
427
|
|
|
$
|
137
|
|
(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.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Natural gas transported (MMBtu/d)
|
8,426,818
|
|
|
8,976,978
|
|
|
(550,160
|
)
|
|||
Revenues
|
$
|
2,250
|
|
|
$
|
2,857
|
|
|
$
|
(607
|
)
|
Cost of products sold
|
1,554
|
|
|
2,169
|
|
|
(615
|
)
|
|||
Gross margin
|
696
|
|
|
688
|
|
|
8
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
(26
|
)
|
|
21
|
|
|
(47
|
)
|
|||
Operating expenses, excluding non-cash compensation expense
|
(163
|
)
|
|
(180
|
)
|
|
17
|
|
|||
Selling, general and administrative, excluding non-cash compensation expense
|
(25
|
)
|
|
(27
|
)
|
|
2
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
61
|
|
|
57
|
|
|
4
|
|
|||
Segment Adjusted EBITDA
|
$
|
543
|
|
|
$
|
559
|
|
|
$
|
(16
|
)
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Transportation fees
|
$
|
502
|
|
|
$
|
466
|
|
|
$
|
36
|
|
Natural gas sales and other
|
96
|
|
|
100
|
|
|
(4
|
)
|
|||
Retained fuel revenues
|
57
|
|
|
98
|
|
|
(41
|
)
|
|||
Storage margin, including fees
|
41
|
|
|
24
|
|
|
17
|
|
|||
Total gross margin
|
$
|
696
|
|
|
$
|
688
|
|
|
$
|
8
|
|
•
|
a decrease of $13 million in natural gas sales and other margin (excluding changes in unrealized gains of $8 million) primarily due to a $19 million decrease in commercial optimization activity as a result of weather driven gains in 2014 not reoccurring in 2015, a $4 million decrease from processing and producer marketing services on our Houston Pipeline System, offset by $10 million in lower losses due to volume adjustments across our pipeline system;
|
•
|
a decrease of $17 million in storage margin, as discussed below; and
|
•
|
a decrease of $44 million from the sale of retained fuel (excluding changes in unrealized gains of $3 million) due to significantly lower market prices. The average spot price at the Houston Ship Channel location for the year ended December 31, 2015 decreased by $1.76, or 41%, to $2.57 as compared to $4.32 for the prior year period; partially offset by
|
•
|
an increase of $36 million in transportation fees margin primarily due to increased revenue from renegotiated and newly initiated long-term fixed capacity fee contracts on our Houston Pipeline system;
|
•
|
a decrease of $2 million in selling, general and administrative expenses primarily due to lower employee-related costs;
|
•
|
a decrease of
$17 million
in operating expenses primarily due to a decrease in fuel consumption expense driven by a decrease in fuel market prices.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Withdrawals from storage natural gas inventory (MMBtu)
|
15,782,500
|
|
|
37,197,510
|
|
|
(21,415,010
|
)
|
|||
Realized margin on natural gas inventory transactions
|
$
|
(2
|
)
|
|
$
|
17
|
|
|
$
|
(19
|
)
|
Fair value inventory adjustments
|
4
|
|
|
(54
|
)
|
|
58
|
|
|||
Unrealized gains on derivatives
|
12
|
|
|
35
|
|
|
(23
|
)
|
|||
Margin recognized on natural gas inventory, including related derivatives
|
14
|
|
|
(2
|
)
|
|
16
|
|
|||
Revenues from fee-based storage
|
27
|
|
|
27
|
|
|
—
|
|
|||
Other costs
|
—
|
|
|
(1
|
)
|
|
1
|
|
|||
Total storage margin
|
$
|
41
|
|
|
$
|
24
|
|
|
$
|
17
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Natural gas transported (MMBtu/d)
|
6,074,282
|
|
|
6,159,546
|
|
|
(85,264
|
)
|
|||
Natural gas sold (MMBtu/d)
|
17,340
|
|
|
16,470
|
|
|
870
|
|
|||
Revenues
|
$
|
1,025
|
|
|
$
|
1,072
|
|
|
$
|
(47
|
)
|
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
|
(304
|
)
|
|
(291
|
)
|
|
(13
|
)
|
|||
Selling, general and administrative, excluding non-cash compensation, amortization and accretion expenses
|
(52
|
)
|
|
(62
|
)
|
|
10
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
486
|
|
|
482
|
|
|
4
|
|
|||
Other
|
—
|
|
|
11
|
|
|
(11
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
1,155
|
|
|
$
|
1,212
|
|
|
$
|
(57
|
)
|
•
|
a decrease of $47 million in revenues primarily due to lower gas parking service related revenues of approximately $19 million as a result of higher basis differentials in 2014 driven by the colder weather, $22 million and $7 million due to the expiration of a transportation rate schedule and lower sales of gas due to lower prices, respectively, on the Transwestern pipeline, and $15 million due to a managed contract roll off on the Trunkline pipeline to facilitate the transfer of one of the pipelines that was taken out of service in advance of being repurposed from natural gas service to crude oil service. These decreases were partially offset by sales of capacity at higher rates of $13 million on the Panhandle and Transwestern pipelines, as well as higher usage rates and volumes on the Transwestern pipeline;
|
•
|
an increase of
$13 million
in operating expenses due to higher employee expenses of approximately $9 million due in part to lower capitalized costs and $3 million of higher ad valorem taxes primarily due to 2014 refunds associated with the settlement of litigation; and
|
•
|
the recognition of an
$11 million
keep-whole payment received from our FEP joint venture, which is included in “Other” in 2014; offset by
|
•
|
a decrease of
$10 million
in selling, general and administration expenses due to reduced franchise taxes of $3.5 million, state tax refund of $1.1 million, favorable insurance, primarily due to a $1.3 million OIL insurance rebate, and reduced corporate overhead allocations of $2.4 million.
|
•
|
an increase of $4 million in adjusted EBITDA related to unconsolidated affiliates primarily due to increased earnings from Citrus as a result of the sale of additional capacity.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Gathered volumes (MMBtu/d):
|
9,981,212
|
|
|
8,079,109
|
|
|
1,902,103
|
|
|||
NGLs produced (Bbls/d):
|
406,149
|
|
|
317,502
|
|
|
88,647
|
|
|||
Equity NGLs (Bbls/d):
|
28,493
|
|
|
27,611
|
|
|
882
|
|
|||
Revenues
|
$
|
5,056
|
|
|
$
|
6,823
|
|
|
$
|
(1,767
|
)
|
Cost of products sold
|
3,264
|
|
|
4,893
|
|
|
(1,629
|
)
|
|||
Gross margin
|
1,792
|
|
|
1,930
|
|
|
(138
|
)
|
|||
Unrealized (gains) losses on commodity risk management activities
|
82
|
|
|
(89
|
)
|
|
171
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(616
|
)
|
|
(481
|
)
|
|
(135
|
)
|
|||
Selling, general and administrative, excluding non-cash compensation expense
|
(44
|
)
|
|
(54
|
)
|
|
10
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
20
|
|
|
12
|
|
|
8
|
|
|||
Other
|
3
|
|
|
—
|
|
|
3
|
|
|||
Segment Adjusted EBITDA
|
$
|
1,237
|
|
|
$
|
1,318
|
|
|
$
|
(81
|
)
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Gathering and processing fee-based revenues
|
$
|
1,570
|
|
|
$
|
1,278
|
|
|
$
|
292
|
|
Non fee-based contracts and processing
|
222
|
|
|
652
|
|
|
(430
|
)
|
|||
Total gross margin
|
$
|
1,792
|
|
|
$
|
1,930
|
|
|
$
|
(138
|
)
|
•
|
a decrease of $88 million in non-fee based margins for natural gas and a $200 million decrease in non-fee based margins for crude oil and NGL due to lower natural gas prices and lower crude oil and NGL prices; and
|
•
|
an increase of $135 million in operating expenses primarily due to assets recently placed in service, including the Rebel system in West Texas and the King Ranch system in South Texas, as well as the acquisition of Eagle Rock midstream assets in July 2014; partially offset by
|
•
|
an increase of $136 million in fee-based revenues primarily due to increased production and increased capacity from assets placed in service in the Marcellus Shale, Eagle Ford Shale, Permian Basin and Cotton Valley;
|
•
|
an increase of $120 million in fee-based margin from the acquisitions of the Eagle Rock, PVR, and King Ranch midstream assets;
|
•
|
an increase of $80 million in realized derivatives;
|
•
|
an increase of $8 million of Adjusted EBITDA related to unconsolidated affiliates due to the addition of the Mi Vida JV asset in the Permian Basin; and
|
•
|
a decrease of $10 million in selling, general and administration expenses due to increased capitalized overhead and higher management fees.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Liquids transportation volumes (Bbls/d)
|
501,666
|
|
|
335,140
|
|
|
166,526
|
|
|||
NGL fractionation volumes (Bbls/d)
|
235,800
|
|
|
189,931
|
|
|
45,869
|
|
|||
Revenues
|
$
|
3,496
|
|
|
$
|
3,911
|
|
|
$
|
(415
|
)
|
Cost of products sold
|
2,597
|
|
|
3,166
|
|
|
(569
|
)
|
|||
Gross margin
|
899
|
|
|
745
|
|
|
154
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
6
|
|
|
(12
|
)
|
|
18
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(152
|
)
|
|
(128
|
)
|
|
(24
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(16
|
)
|
|
(20
|
)
|
|
4
|
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
7
|
|
|
6
|
|
|
1
|
|
|||
Segment Adjusted EBITDA
|
$
|
744
|
|
|
$
|
591
|
|
|
$
|
153
|
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Transportation margin
|
$
|
394
|
|
|
$
|
312
|
|
|
$
|
82
|
|
Processing and fractionation margin
|
297
|
|
|
247
|
|
|
50
|
|
|||
Storage margin
|
172
|
|
|
157
|
|
|
15
|
|
|||
Other margin
|
36
|
|
|
29
|
|
|
7
|
|
|||
Total gross margin
|
$
|
899
|
|
|
$
|
745
|
|
|
$
|
154
|
|
•
|
an increase of $69 million in transportation margin primarily due to higher volumes transported out of West Texas and the Eagle Ford producing regions. Increased volumes out of West Texas led to $47 million in additional transportation fees, while increased volumes from the Eagle Ford region led to $15 million in additional transportation fees for the year ended December 31, 2015. We also realized an increase of $7 million for the year ended December 31, 2015 from our crude pipeline, which was commissioned in the fourth quarter of 2014;
|
•
|
an increase of $42 million in processing and fractionation margin (excluding changes in unrealized gains of $8 million) due to $9 million increase in margin from our fractionators due to the ramp-up of our second 100,000 Bbls/d fractionator at Mont Belvieu, Texas, and the additional volumes from producers in West Texas and the Eagle Ford regions offset by reductions in blending gains due to lower market prices. Additionally, the commissioning of the Mariner South LPG export project during February 2015 contributed an additional $50 million for the twelve months ended December 31, 2015. Margin associated
|
•
|
an increase of $15 million in storage margin due to a $24 million increase in fee based storage margin for year ended December 31, 2015 from an increase in demand for leased storage capacity as a result of favorable market conditions and a specific contract negotiated in connection with the Mariner South LPG export project. The increase in fee based storage margin was offset by lower non-fee based margin of $8 million for the year ended December 31, 2015 primarily due to lower propane blending gains;
|
•
|
an increase of $33 million in other margin (excluding changes in unrealized losses of $26 million) primarily due to the withdrawal and sale of physical storage volumes, primarily propane and butanes; and
|
•
|
a decrease of
$4 million
in selling, general and administrative expenses primarily due to lower employee-related costs; partially offset by
|
•
|
an increase of $24 million in operating expenses primarily due to a $6 million increase in employee expenses, a $4 million increase in ad valorem taxes, a $3 million increase in utilities expense, a $6 million increase in project costs and materials and supplies expense, and a $5 million increase in overhead expense allocations.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Revenue
|
$
|
10,486
|
|
|
$
|
18,088
|
|
|
$
|
(7,602
|
)
|
Cost of products sold
|
9,307
|
|
|
17,135
|
|
|
(7,828
|
)
|
|||
Gross margin
|
1,179
|
|
|
953
|
|
|
226
|
|
|||
Unrealized (gains) losses on commodity risk management activities
|
4
|
|
|
(17
|
)
|
|
21
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(158
|
)
|
|
(167
|
)
|
|
9
|
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(92
|
)
|
|
(107
|
)
|
|
15
|
|
|||
Inventory valuation adjustments
|
162
|
|
|
258
|
|
|
(96
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
58
|
|
|
49
|
|
|
9
|
|
|||
Other
|
—
|
|
|
2
|
|
|
(2
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
1,153
|
|
|
$
|
971
|
|
|
$
|
182
|
|
•
|
an increase of $130 million from Sunoco Logistics’ NGLs operations, primarily due to contributions from Sunoco Logistics’ Mariner NGLs projects which commenced operations in late 2014 and 2013. These projects contributed to improved results related to Sunoco Logistics’ NGLs pipeline and terminal operations of $160 million, including Sunoco Logistics’ Nederland and Marcus Hook facilities. These positive impacts were partially offset by lower results from Sunoco Logistics’ NGLs acquisition and marketing activities of $33 million driven largely by narrowed blending margins compared to the prior year period; and
|
•
|
an increase of $65 million from Sunoco Logistics’ refined products operations, primarily due to higher results from Sunoco Logistics’ refined products pipelines of $33 million driven largely by the commencement of operations on Sunoco Logistics’ Allegheny Access project in 2015. Terminalling activities at Sunoco Logistics’ refined products marketing terminals, as well as Sunoco Logistics’ Eagle Point and Marcus Hook facilities, increased compared to the prior year period by $15 million. Higher contributions from Sunoco Logistics’ joint venture interests of $10 million and refined products acquisition and marketing activities of $6 million also contributed to the increase; offset by
|
•
|
a decrease of $13 million from Sunoco Logistics’ crude oil operations, primarily due to lower results from Sunoco Logistics’ crude oil acquisition and marketing activities of $96 million driven by reduced margins which were negatively impacted by contracted crude oil differentials compared to the prior year period. This impact was partially offset by higher results from Sunoco Logistics’ crude oil pipelines of $71 million largely attributable to expansion projects placed into service in 2015 and 2014, and higher results from Sunoco Logistics’ crude oil terminals of $14 million.
|
|
Years Ended December 31,
|
|
|
||||||||
|
2015
|
|
2014
|
|
Change
|
||||||
Revenue
|
$
|
15,774
|
|
|
$
|
25,818
|
|
|
$
|
(10,044
|
)
|
Cost of products sold
|
14,029
|
|
|
24,129
|
|
|
(10,100
|
)
|
|||
Gross margin
|
1,745
|
|
|
1,689
|
|
|
56
|
|
|||
Unrealized gains on commodity risk management activities
|
(1
|
)
|
|
(15
|
)
|
|
14
|
|
|||
Operating expenses, excluding non-cash compensation expense
|
(896
|
)
|
|
(840
|
)
|
|
(56
|
)
|
|||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(254
|
)
|
|
(251
|
)
|
|
(3
|
)
|
|||
Adjusted EBITDA related to discontinued operations
|
—
|
|
|
27
|
|
|
(27
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
313
|
|
|
149
|
|
|
164
|
|
|||
Inventory valuation adjustments
|
(58
|
)
|
|
215
|
|
|
(273
|
)
|
|||
Other
|
95
|
|
|
93
|
|
|
2
|
|
|||
Elimination
|
(62
|
)
|
|
(8
|
)
|
|
(54
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
882
|
|
|
$
|
1,059
|
|
|
$
|
(177
|
)
|
•
|
our
retail marketing operations prior to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016
;
|
•
|
our equity method investment in limited partnership units of Sunoco LP consisting of 37.8 million Sunoco LP common units;
|
•
|
our natural gas marketing and compression operations;
|
•
|
a non-controlling interest in PES, comprising
33%
of PES’ outstanding common units;
|
•
|
our investment in Coal Handling, an entity that owns and operates end-user coal handling facilities; and
|
•
|
our investment in AmeriGas until August 2014.
|
•
|
a decrease of $124 million due to the deconsolidation of Sunoco LP as a result of the sale of Sunoco LP’s general partner interest and incentive distribution rights to ETE effective July 1, 2015;
|
•
|
a decrease of $121 million due to unfavorable fuel margins and $9 million due to unfavorable volumes in the retail and wholesale channels;
|
•
|
a decrease of $49 million in margins as 2014 benefited from favorable regional market conditions for ethanol;
|
•
|
a decrease of $63 million in Adjusted EBITDA related to unconsolidated affiliates, primarily due to a decrease of $56 million related to our investment in AmeriGas driven by a reduction in our investment due to the sale of AmeriGas common units in 2014; and
|
•
|
a decrease in Adjusted EBITDA related to discontinued operations of $27 million in the prior period related to a marketing business that was sold effective April 1, 2014; partially offset by
|
•
|
the favorable impact of $112 million from the acquisition of Susser in August 2014 until its contribution to Sunoco LP in July 2015 and $43 million from other recent acquisitions.
|
•
|
an increase of $21 million related to our contract services operations primarily due to an increase in revenue-generating horsepower; and
|
•
|
an increase of $17 million related to our natural resources operations, for which the period reflected only a partial period due to the acquisition of those operations in March 2014.
|
|
Growth
|
|
Maintenance
|
||||||||||||
|
Low
|
|
High
|
|
Low
|
|
High
|
||||||||
Direct
(1)
:
|
|
|
|
|
|
|
|
||||||||
Intrastate transportation and storage
|
$
|
30
|
|
|
$
|
40
|
|
|
$
|
20
|
|
|
$
|
25
|
|
Interstate transportation and storage
(2)
|
1,750
|
|
|
1,790
|
|
|
100
|
|
|
110
|
|
||||
Midstream
|
935
|
|
|
985
|
|
|
120
|
|
|
130
|
|
||||
Liquids transportation and services:
|
|
|
|
|
|
|
|
||||||||
NGL
|
370
|
|
|
390
|
|
|
20
|
|
|
25
|
|
||||
Crude
(2)
|
200
|
|
|
230
|
|
|
—
|
|
|
5
|
|
||||
All other (including eliminations)
|
70
|
|
|
80
|
|
|
65
|
|
|
70
|
|
||||
Total direct capital expenditures
|
3,355
|
|
|
3,515
|
|
|
325
|
|
|
365
|
|
||||
Less: Project level non-recourse financing
|
(600
|
)
|
|
(600
|
)
|
|
—
|
|
|
—
|
|
||||
Partnership level capital funding
|
$
|
2,755
|
|
|
$
|
2,915
|
|
|
$
|
325
|
|
|
$
|
365
|
|
(1)
|
Direct capital expenditures exclude those funded by our publicly-traded subsidiary.
|
(2)
|
Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.
|
|
Capital Expenditures Recorded During Period
|
||||||||||
Growth
|
|
Maintenance
|
|
Total
|
|||||||
Year Ended December 31, 2016:
|
|
|
|
|
|
||||||
Direct
(1)
:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
53
|
|
|
$
|
23
|
|
|
$
|
76
|
|
Interstate transportation and storage
(2)
|
191
|
|
|
89
|
|
|
280
|
|
|||
Midstream
|
1,133
|
|
|
122
|
|
|
1,255
|
|
|||
Liquids transportation and services
(2)
|
2,296
|
|
|
20
|
|
|
2,316
|
|
|||
All other (including eliminations)
|
93
|
|
|
51
|
|
|
144
|
|
|||
Total direct capital expenditures
|
3,766
|
|
|
305
|
|
|
4,071
|
|
|||
Indirect
(1)
:
|
|
|
|
|
|
||||||
Investment in Sunoco Logistics
|
1,676
|
|
|
63
|
|
|
1,739
|
|
|||
Total capital expenditures
|
$
|
5,442
|
|
|
$
|
368
|
|
|
$
|
5,810
|
|
|
|
|
|
|
|
||||||
Year Ended December 31, 2015:
|
|
|
|
|
|
||||||
Direct
(1)
:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
74
|
|
|
$
|
31
|
|
|
$
|
105
|
|
Interstate transportation and storage
|
741
|
|
|
119
|
|
|
860
|
|
|||
Midstream
|
2,055
|
|
|
117
|
|
|
2,172
|
|
|||
Liquids transportation and services
|
2,091
|
|
|
18
|
|
|
2,109
|
|
|||
All other (including eliminations)
|
596
|
|
|
109
|
|
|
705
|
|
|||
Total direct capital expenditures
|
5,557
|
|
|
394
|
|
|
5,951
|
|
|||
Indirect
(1)
:
|
|
|
|
|
|
||||||
Investment in Sunoco Logistics
|
2,042
|
|
|
84
|
|
|
2,126
|
|
|||
Investment in Sunoco LP
(3)
|
83
|
|
|
7
|
|
|
90
|
|
|||
Total indirect capital expenditures
|
2,125
|
|
|
91
|
|
|
2,216
|
|
|||
Total capital expenditures
|
$
|
7,682
|
|
|
$
|
485
|
|
|
$
|
8,167
|
|
|
|
|
|
|
|
||||||
Year Ended December 31, 2014:
|
|
|
|
|
|
||||||
Direct
(1)
:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
133
|
|
|
$
|
36
|
|
|
$
|
169
|
|
Interstate transportation and storage
|
301
|
|
|
110
|
|
|
411
|
|
|||
Midstream
|
1,204
|
|
|
94
|
|
|
1,298
|
|
|||
Liquids transportation and services
|
406
|
|
|
21
|
|
|
427
|
|
|||
All other (including eliminations)
|
495
|
|
|
102
|
|
|
597
|
|
|||
Total direct capital expenditures
|
2,539
|
|
|
363
|
|
|
2,902
|
|
|||
Indirect
(1)
:
|
|
|
|
|
|
||||||
Investment in Sunoco Logistics
|
2,434
|
|
|
76
|
|
|
2,510
|
|
|||
Investment in Sunoco LP
(3)
|
77
|
|
|
5
|
|
|
82
|
|
|||
Total indirect capital expenditures
|
2,511
|
|
|
81
|
|
|
2,592
|
|
|||
Total capital expenditures
|
$
|
5,050
|
|
|
$
|
444
|
|
|
$
|
5,494
|
|
(1)
|
Indirect capital expenditures comprise those funded by our publicly traded subsidiary; all other capital expenditures are reflected as direct capital expenditures.
|
(2)
|
Includes capital expenditures related to the Bakken, Rover and Bayou Bridge pipeline projects, which includes
$572 million
related to Sunoco Logistics’ proportionate ownership in the Bakken and Bayou Bridge projects. Capital expenditures include
|
(3)
|
Investment in Sunoco LP includes capital expenditures for the period prior to deconsolidation on July 1, 2015.
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
ETP Senior Notes
|
$
|
19,440
|
|
|
$
|
19,439
|
|
Transwestern Senior Notes
|
657
|
|
|
782
|
|
||
Panhandle Senior Notes
|
1,085
|
|
|
1,085
|
|
||
Sunoco, Inc. Senior Notes
|
465
|
|
|
465
|
|
||
Sunoco Logistics Senior Notes
|
5,350
|
|
|
4,975
|
|
||
Revolving credit facilities:
|
|
|
|
||||
ETP $3.75 billion Revolving Credit Facility due November 2019
|
2,777
|
|
|
1,362
|
|
||
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020
|
1,292
|
|
|
562
|
|
||
Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017
(1)
|
630
|
|
|
—
|
|
||
Bakken Project $2.50 billion Credit Facility due August 2019
|
1,100
|
|
|
—
|
|
||
PennTex $275 million Revolving Credit Facility due December 2019
|
168
|
|
|
—
|
|
||
Other long-term debt
|
30
|
|
|
32
|
|
||
Unamortized premiums, net of discounts and fair value adjustments
|
116
|
|
|
158
|
|
||
Deferred debt issuance costs
|
(180
|
)
|
|
(181
|
)
|
||
Total debt
|
32,930
|
|
|
28,679
|
|
||
Less: current maturities of long-term debt
|
1,189
|
|
|
126
|
|
||
Long-term debt, less current maturities
|
$
|
31,741
|
|
|
$
|
28,553
|
|
(1)
|
Sunoco Logistics’ $1.0 billion 364-Day Credit Facility, including its
$630 million
term loan, were classified as long-term debt as of
December 31, 2016
as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis.
|
•
|
incur indebtedness;
|
•
|
grant liens;
|
•
|
enter into mergers;
|
•
|
dispose of assets;
|
•
|
make certain investments;
|
•
|
make Distributions (as defined in the ETP Credit Facility) during certain Defaults (as defined in the ETP Credit Facility) and during any Event of Default (as defined in the ETP Credit Facility);
|
•
|
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
|
•
|
engage in transactions with affiliates; and
|
•
|
enter into restrictive agreements.
|
•
|
prohibition of certain incremental secured indebtedness;
|
•
|
prohibition of certain liens / negative pledge;
|
•
|
limitations on uses of loan proceeds;
|
•
|
limitations on asset sales and purchases;
|
•
|
limitations on permitted business activities;
|
•
|
limitations on mergers and acquisitions;
|
•
|
limitations on investments;
|
•
|
limitations on transactions with affiliates; and
|
•
|
maintenance of commercially reasonable insurance coverage.
|
|
|
Payments Due by Period
|
||||||||||||||||||
Contractual Obligations
|
|
Total
|
|
Less Than 1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than 5 Years
|
||||||||||
Long-term debt
|
|
$
|
32,994
|
|
|
$
|
1,812
|
|
|
$
|
6,695
|
|
|
$
|
5,067
|
|
|
$
|
19,420
|
|
Interest on long-term debt
(1)
|
|
19,328
|
|
|
1,554
|
|
|
2,782
|
|
|
2,319
|
|
|
12,673
|
|
|||||
Payments on derivatives
|
|
194
|
|
|
120
|
|
|
74
|
|
|
—
|
|
|
—
|
|
|||||
Purchase commitments
(2)
|
|
6,799
|
|
|
4,444
|
|
|
929
|
|
|
621
|
|
|
805
|
|
|||||
Transportation, natural gas storage and fractionation contracts
|
|
44
|
|
|
24
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|||||
Operating lease obligations
|
|
292
|
|
|
38
|
|
|
58
|
|
|
63
|
|
|
133
|
|
|||||
Other
(3)
|
|
46
|
|
|
8
|
|
|
15
|
|
|
15
|
|
|
8
|
|
|||||
Total
(4)
|
|
$
|
59,697
|
|
|
$
|
8,000
|
|
|
$
|
10,573
|
|
|
$
|
8,085
|
|
|
$
|
33,039
|
|
(1)
|
Interest payments on long-term debt are based on the principal amount of debt obligations as of
December 31, 2016
. With respect to variable rate debt, the interest payments were estimated using the interest rate as of
December 31, 2016
. 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, 2016
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)
|
Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, asset retirement obligations, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” our consolidated balance sheets were excluded from the table above as such amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain.
|
(4)
|
Excludes non-current deferred tax liabilities of
$4.39 billion
due to uncertainty of the timing of future cash flows for such liabilities.
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2013
|
|
February 7, 2014
|
|
February 14, 2014
|
|
$
|
0.9200
|
|
March 31, 2014
|
|
May 5, 2014
|
|
May 15, 2014
|
|
0.9350
|
|
|
June 30, 2014
|
|
August 4, 2014
|
|
August 14, 2014
|
|
0.9550
|
|
|
September 30, 2014
|
|
November 3, 2014
|
|
November 14, 2014
|
|
0.9750
|
|
|
December 31, 2014
|
|
February 6, 2015
|
|
February 13, 2015
|
|
0.9950
|
|
|
March 31, 2015
|
|
May 8, 2015
|
|
May 15, 2015
|
|
1.0150
|
|
|
June 30, 2015
|
|
August 6, 2015
|
|
August 14, 2015
|
|
1.0350
|
|
|
September 30, 2015
|
|
November 5, 2015
|
|
November 16, 2015
|
|
1.0550
|
|
|
December 31, 2015
|
|
February 8, 2016
|
|
February 16, 2016
|
|
1.0550
|
|
|
March 31, 2016
|
|
May 6, 2016
|
|
May 16, 2016
|
|
1.0550
|
|
|
June 30, 2016
|
|
August 8, 2016
|
|
August 15, 2016
|
|
1.0550
|
|
|
September 30, 2016
|
|
November 7, 2016
|
|
November 14, 2016
|
|
1.0550
|
|
|
December 31, 2016
|
|
February 7, 2017
|
|
February 14, 2017
|
|
1.0550
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Common Units held by public
(1)
|
$
|
2,168
|
|
|
$
|
1,970
|
|
|
$
|
1,179
|
|
Common Units held by ETE
|
28
|
|
|
54
|
|
|
119
|
|
|||
Class H Units held by ETE
|
357
|
|
|
263
|
|
|
219
|
|
|||
General Partner interest held by ETE
|
32
|
|
|
31
|
|
|
21
|
|
|||
Incentive distributions held by ETE
(1)
|
1,363
|
|
|
1,261
|
|
|
754
|
|
|||
IDR relinquishments net of Class I unit distributions
|
(409
|
)
|
|
(111
|
)
|
|
(250
|
)
|
|||
Total distributions declared to the partners of ETP
|
$
|
3,539
|
|
|
$
|
3,468
|
|
|
$
|
2,042
|
|
(1)
|
The increases for the year ended December 31, 2015 include the impacts from Common Units issued in the Regency Merger, as well as increases in distributions per unit.
|
|
|
Total Year
|
||
2017
|
|
$
|
626
|
|
2018
|
|
138
|
|
|
2019
|
|
128
|
|
|
Each year beyond 2019
|
|
33
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2013
|
|
February 10, 2014
|
|
February 14, 2014
|
|
$
|
0.3312
|
|
March 31, 2014
|
|
May 9, 2014
|
|
May 15, 2014
|
|
0.3475
|
|
|
June 30, 2014
|
|
August 8, 2014
|
|
August 14, 2014
|
|
0.3650
|
|
|
September 30, 2014
|
|
November 7, 2014
|
|
November 14, 2014
|
|
0.3825
|
|
|
December 31, 2014
|
|
February 9, 2015
|
|
February 13, 2015
|
|
0.4000
|
|
|
March 31, 2015
|
|
May 11, 2015
|
|
May 15, 2015
|
|
0.4190
|
|
|
June 30, 2015
|
|
August 10, 2015
|
|
August 14, 2015
|
|
0.4380
|
|
|
September 30, 2015
|
|
November 9, 2015
|
|
November 13, 2015
|
|
0.4580
|
|
|
December 31, 2015
|
|
February 8, 2016
|
|
February 12, 2016
|
|
0.4790
|
|
|
March 31, 2016
|
|
May 9, 2016
|
|
May 13, 2016
|
|
0.4890
|
|
|
June 30, 2016
|
|
August 8, 2016
|
|
August 12, 2016
|
|
0.5000
|
|
|
September 30, 2016
|
|
November 9, 2016
|
|
November 14, 2016
|
|
0.5100
|
|
|
December 31, 2016
|
|
February 7, 2017
|
|
February 14, 2017
|
|
0.5200
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Limited Partners:
|
|
|
|
|
|
||||||
Common units held by public
|
$
|
485
|
|
|
$
|
344
|
|
|
$
|
225
|
|
Common units held by ETP
|
135
|
|
|
120
|
|
|
100
|
|
|||
General Partner interest held by ETP
|
15
|
|
|
12
|
|
|
10
|
|
|||
Incentive distributions held by ETP
|
397
|
|
|
281
|
|
|
175
|
|
|||
IDR reduction
|
(15
|
)
|
|
—
|
|
|
—
|
|
|||
Total distributions declared
|
$
|
1,017
|
|
|
$
|
757
|
|
|
$
|
510
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
September 30, 2016
|
|
November 7, 2016
|
|
November 14, 2016
|
|
$
|
0.2950
|
|
December 31, 2016
|
|
February 7, 2017
|
|
February 14, 2017
|
|
0.2950
|
|
•
|
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, 2016
|
|
December 31, 2015
|
||||||||||||||||||
|
Notional Volume
|
|
Fair Value Asset (Liability)
|
|
Effect of Hypothetical 10% Change
|
|
Notional Volume
|
|
Fair Value Asset (Liability)
|
|
Effect of Hypothetical 10% Change
|
||||||||||
Mark-to-Market Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Swaps/Futures
|
(682,500
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
(602,500
|
)
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
Basis Swaps IFERC/NYMEX
(1)
|
2,242,500
|
|
|
(1
|
)
|
|
—
|
|
|
(31,240,000
|
)
|
|
(1
|
)
|
|
—
|
|
||||
Power (Megawatt):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Forwards
|
391,880
|
|
|
(1
|
)
|
|
1
|
|
|
357,092
|
|
|
—
|
|
|
2
|
|
||||
Futures
|
109,564
|
|
|
—
|
|
|
—
|
|
|
(109,791
|
)
|
|
2
|
|
|
—
|
|
||||
Options – Puts
|
(50,400
|
)
|
|
—
|
|
|
—
|
|
|
260,534
|
|
|
—
|
|
|
—
|
|
||||
Options – Calls
|
186,400
|
|
|
1
|
|
|
—
|
|
|
1,300,647
|
|
|
—
|
|
|
3
|
|
||||
Crude (Bbls) – Futures
|
(617,000
|
)
|
|
(4
|
)
|
|
6
|
|
|
(591,000
|
)
|
|
4
|
|
|
3
|
|
||||
(Non-Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basis Swaps IFERC/NYMEX
|
10,750,000
|
|
|
2
|
|
|
—
|
|
|
(6,522,500
|
)
|
|
—
|
|
|
—
|
|
||||
Swing Swaps IFERC
|
(5,662,500
|
)
|
|
(1
|
)
|
|
1
|
|
|
71,340,000
|
|
|
(1
|
)
|
|
—
|
|
||||
Fixed Swaps/Futures
|
(52,652,500
|
)
|
|
(27
|
)
|
|
19
|
|
|
(14,380,000
|
)
|
|
(1
|
)
|
|
5
|
|
||||
Forward Physical Contracts
|
(22,492,489
|
)
|
|
1
|
|
|
8
|
|
|
21,922,484
|
|
|
4
|
|
|
5
|
|
||||
Natural Gas Liquid (Bbls) – Forwards/Swaps
|
(5,786,627
|
)
|
|
(40
|
)
|
|
35
|
|
|
(8,146,800
|
)
|
|
10
|
|
|
13
|
|
||||
Refined Products (Bbls) – Futures
|
(2,240,000
|
)
|
|
(16
|
)
|
|
17
|
|
|
(939,000
|
)
|
|
9
|
|
|
5
|
|
||||
Corn (Bushels) – Futures
|
—
|
|
|
—
|
|
|
—
|
|
|
1,185,000
|
|
|
—
|
|
|
1
|
|
||||
Fair Value Hedging Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Non-Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basis Swaps IFERC/NYMEX
|
(36,370,000
|
)
|
|
2
|
|
|
1
|
|
|
(37,555,000
|
)
|
|
—
|
|
|
—
|
|
||||
Fixed Swaps/Futures
|
(36,370,000
|
)
|
|
(26
|
)
|
|
14
|
|
|
(37,555,000
|
)
|
|
73
|
|
|
9
|
|
(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, 2016
|
|
December 31, 2015
|
||||||
July 2016
(2)
|
|
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
|
|
—
|
|
|
200
|
|
July 2017
(3)
|
|
Forward-starting to pay a fixed rate of 3.90% and receive a floating rate
|
|
500
|
|
|
300
|
|
July 2018
(3)
|
|
Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
|
|
200
|
|
|
200
|
|
July 2019
(3)
|
|
Forward-starting to pay a fixed rate of 3.25% and receive a floating rate
|
|
200
|
|
|
200
|
|
December 2018
|
|
Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
|
|
1,200
|
|
|
1,200
|
|
March 2019
|
|
Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
|
|
300
|
|
|
300
|
|
(1)
|
Floating rates are based on 3-month LIBOR.
|
(2)
|
Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
|
(3)
|
Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
|
•
|
annually review and approve goals and objectives relevant to compensation of the CEO, if applicable;
|
•
|
annually evaluate the CEO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the CEO’s compensation levels, if applicable, based on this evaluation;
|
•
|
based on input from, and discussion with, the CEO, make recommendations to the Board of Directors with respect to non-CEO executive officer compensation, including incentive compensation and compensation under equity- based plans;
|
•
|
make determinations with respect to the grant of equity-based awards to executive officers under our equity incentive plans;
|
•
|
periodically evaluate the terms and administration of ETP’s short-term and long-term incentive plans to assure that they are structured and administered in a manner consistent with ETP’s goals and objectives;
|
•
|
periodically evaluate incentive compensation and equity-related plans and consider amendments, if appropriate;
|
•
|
periodically evaluate the compensation of the directors;
|
•
|
retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO or executive officer compensation; and
|
•
|
perform other duties as deemed appropriate by the Board of Directors.
|
Name
|
|
Age
|
|
|
Position with Our General Partner
|
Kelcy L. Warren
|
|
61
|
|
|
Chief Executive Officer and Chairman of the Board of Directors
|
Matthew S. Ramsey
|
|
61
|
|
|
Director, President and Chief Operating Officer
|
Thomas E. Long
|
|
60
|
|
|
Chief Financial Officer
|
Marshall S. (Mackie) McCrea, III
|
|
57
|
|
|
Director and ETE Group Chief Operating Officer and Chief Commercial Officer
|
James M. Wright, Jr.
|
|
48
|
|
|
General Counsel
|
Michael J. Hennigan
|
|
57
|
|
|
President and Chief Executive Officer of Sunoco Logistics
|
A. Troy Sturrock
|
|
46
|
|
|
Senior Vice President, Controller and Principal Accounting Officer
|
Ted Collins, Jr.
|
|
78
|
|
|
Director
|
Michael K. Grimm
|
|
62
|
|
|
Director
|
David K. Skidmore
|
|
61
|
|
|
Director
|
•
|
Kelcy L. Warren, Chairman and Chief Executive Officer;
|
•
|
Thomas E. Long, Chief Financial Officer and Group Chief Financial Officer of ETE’s general partner;
|
•
|
Matthew S. Ramsey, President and Chief Operating Officer;
|
•
|
James M. Wright, General Counsel and Assistant Secretary; and
|
•
|
Michael J. Hennigan, President and Chief Executive Officer of Sunoco Partners LLC.
|
•
|
reward executives with an industry-competitive total compensation package of targeted 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 unit awards under the equity incentive plan(s);
|
•
|
payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit awards under the equity incentive plan(s);
|
•
|
vesting of previously issued time-based restricted unit/phantom restricted unit awards issued pursuant to the ETP equity incentive plan(s) or the equity incentive plan(s) of its affiliates; and
|
•
|
401(k) plan employer contributions.
|
Energy Peer Group:
|
|
|
• Conoco Phillips
|
|
• Anadarko Petroleum
|
• Enterprise Products Partners, L.P.
|
|
• Marathon Oil Corporation
|
• Plains All American Pipeline, L.P.
|
|
• Kinder Morgan Energy Partners, L.P.
|
• Halliburton Company
|
|
• The Williams Companies, Inc.
|
• Valero Energy Corporation
|
|
|
General Industry Peer Group:
|
|
|
• The Boeing Company
|
|
• United Technologies Corporation
|
• Dow Chemical Company
|
|
• United Parcel Service, Inc.
|
• Caterpillar Inc.
|
|
• FedEx Corporation
|
• Lockheed Martin Corporation
|
|
• Honeywell International Inc.
|
• Deere & Company
|
|
|
Energy Peer Group:
|
|
|
• Buckeye Partners, L.P.
|
|
• PBF Energy Inc.
|
• Enbridge Energy Partners, L.P.
|
|
• Plains All American Pipeline, L.P.
|
• HollyFrontier Corporation
|
|
• Spectra Energy Corp.
|
• MarkWest Energy Partners, L.P.
|
|
• Targa Resources Corp.
|
• NGL Energy Partners LP
|
|
• Tesoro Corporation
|
• ONEOK Inc.
|
|
|
Name and Principal Position
|
|
Year
|
|
Salary
($)
|
|
Bonus
(1)
($)
|
|
Equity
Awards
(2)
($)
|
|
Option
Awards
($)
|
|
Non-Equity
Incentive Plan
Compensation
($)
|
|
Change in Pension
Value and
Nonqualified Deferred Compensation Earnings
(3)
($)
|
|
All Other
Compensation
(4)
($)
|
|
Total
($)
|
||||||||||||||||
Kelcy L. Warren
(5)
|
|
2016
|
|
$
|
5,920
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
58
|
|
|
$
|
5,978
|
|
Chief Executive Officer
|
|
2015
|
|
6,338
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,338
|
|
||||||||
|
2014
|
|
6,921
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,921
|
|
|||||||||
Thomas E. Long
|
|
2016
|
|
454,154
|
|
|
560,865
|
|
|
2,007,697
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,679
|
|
|
3,037,395
|
|
||||||||
Chief Financial Officer
|
|
2015
|
|
399,207
|
|
|
480,296
|
|
|
1,447,063
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,282
|
|
|
2,340,848
|
|
||||||||
|
2014
|
|
326,221
|
|
|
391,465
|
|
|
777,850
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,032
|
|
|
1,509,568
|
|
|||||||||
Matthew S. Ramsey
(6)
|
|
2016
|
|
630,769
|
|
|
838,901
|
|
|
3,433,894
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
87,375
|
|
|
4,990,939
|
|
||||||||
President and Chief Operating Officer
|
|
2015
|
|
72,115
|
|
|
200,000
|
|
|
2,749,161
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,587
|
|
|
3,023,863
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
James M. Wright, Jr.
|
|
2016
|
|
378,462
|
|
|
377,506
|
|
|
858,464
|
|
|
—
|
|
|
—
|
|
|
47,766
|
|
|
14,447
|
|
|
1,676,645
|
|
||||||||
General Counsel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Michael J. Hennigan
(7)
|
|
2016
|
|
630,769
|
|
|
830,092
|
|
|
3,088,040
|
|
|
—
|
|
|
—
|
|
|
360,066
|
|
|
14,818
|
|
|
4,923,785
|
|
||||||||
President and Chief Executive Officer of Sunoco Partners LLC
|
|
2015
|
|
611,537
|
|
|
856,152
|
|
|
3,009,815
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16,770
|
|
|
4,494,274
|
|
||||||||
|
2014
|
|
600,000
|
|
|
810,000
|
|
|
3,941,118
|
|
|
—
|
|
|
—
|
|
|
263,923
|
|
|
27,192
|
|
|
5,642,233
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The discretionary cash bonus amounts for named executive officers for
2016
reflect cash bonuses approved by the ETE Compensation Committee, the ETP Compensation Committee and the Sunoco Logistics Compensation Committee in February 2017 that are expected to be paid on or before March 15, 2017.
|
(2)
|
Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. For Mr. Long, amounts include equity awards of our subsidiaries and affiliates, as reflected in the “Grants of Plan-Based Awards Table.” See
Note 9
to our consolidated financial statements for additional assumptions underlying the value of the equity awards.
|
(3)
|
During 2016, Mr. Wright had a gain of $47,766 under the DC Plan and Mr. Hennigan had a gain of $360,066 under the Sunoco Logistics DC Plan.
|
(4)
|
The amounts reflected for
2016
in this column include (i) matching contributions to the 401(k) plan made by ETP on behalf of the named executive officers of
$13,250
for each of Messrs. Long, Ramsey, Wright and Hennigan, (ii) the dollar value of life insurance premiums paid for the benefit of the named executive officers and (iii) $72,557 in relocation costs for Mr. Ramsey.
|
(5)
|
Mr. Warren voluntarily determined that his salary would 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.
|
(6)
|
Mr. Ramsey serves as a member of the board of directors of ETE, the owner of our General Partner. Mr. Ramsey’s other compensation for 2015 does not include $104,400 of director fees paid in cash by ETE. Mr. Ramsey was also a non-employee director of Sunoco LP during 2015, until his November appointment to our General Partner, and his 2015 other compensation does not include $354,210 of director fees paid in cash by Sunoco LP.
|
(7)
|
The amounts shown for Mr. Hennigan reflect the change in present value for all defined benefit pension plans and supplemental executive retirement plans in which he participated. The applicable disclosure rules require the change in pension value be shown as “$0” if the actual calculation of the change in pension value is less than zero (
i.e
., a decrease). The decrease in SCIRP pension value for Mr. Hennigan was $49,762 for 2015. The year-over-year change in actuarial present value of Mr. Hennigan’s pension benefits under the SCIRP for 2015 was negative because Sunoco, Inc. terminated the SCIRP on October 31, 2014. Mr. Hennigan elected to receive his accrued SCIRP benefit in the form of a lump sum. Because the estimate of the present value of his SCIRP benefit at year-end 2014 assumed that Mr. Hennigan (under the Final Average Pay formula) had a 90 percent probability of electing a lump sum rather than an annuity (which would be transferred to an insurance company
|
Name
|
|
Grant Date
|
|
All Other Unit Awards: Number of Units
(#)
|
|
All Other Option Awards: Number of Securities Underlying Options
(#)
|
|
Exercise or Base Price of Option Awards
($ / Unit)
|
|
Grant Date Fair Value of Unit Awards
(1)
|
||||||
ETP Unit Awards:
|
|
|
|
|
|
|
|
|
|
|
||||||
Kelcy L. Warren
|
|
N/A
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Thomas E. Long
|
|
12/29/2016
|
|
28,688
|
|
|
—
|
|
|
—
|
|
|
1,030,186
|
|
||
Matthew S. Ramsey
|
|
12/26/2016
|
|
95,625
|
|
|
—
|
|
|
—
|
|
|
3,433,894
|
|
||
James M. Wright, Jr.
|
|
12/29/2016
|
|
23,906
|
|
|
—
|
|
|
—
|
|
|
858,464
|
|
||
Michael J. Hennigan
|
|
N/A
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Sunoco Logistics Unit Awards:
|
|
|
|
|
|
|
|
|
|
|
||||||
Thomas E. Long
|
|
12/29/2016
|
|
16,021
|
|
|
—
|
|
|
—
|
|
|
384,504
|
|
||
Michael J. Hennigan
|
|
12/12/2016
|
|
133,508
|
|
|
—
|
|
|
—
|
|
|
3,088,040
|
|
||
Sunoco LP Unit Awards:
|
|
|
|
|
|
|
|
|
|
|
||||||
Thomas E. Long
|
|
12/29/2016
|
|
22,210
|
|
|
—
|
|
|
—
|
|
|
593,007
|
|
(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 9
to our consolidated financial statements.
|
|
|
|
|
Unit Awards
|
|||||
Name
|
|
Grant Date
(1)
|
|
Number of Units That Have Not Vested
(1)(2)
(#)
|
|
Market or Payout Value of Units That Have Not Vested
(3)
($)
|
|||
ETP Unit Awards:
|
|
|
|
|
|
|
|||
Kelcy L. Warren
|
|
—
|
|
—
|
|
|
$
|
—
|
|
Thomas E. Long
|
|
12/29/2016
|
|
28,688
|
|
|
1,027,317
|
|
|
|
|
12/9/2015
|
|
18,525
|
|
|
663,380
|
|
|
|
|
12/16/2014 (4)
|
|
13,651
|
|
|
488,842
|
|
|
|
|
12/5/2013 (4)
|
|
4,344
|
|
|
155,559
|
|
|
|
|
12/5/2012 (4)
|
|
4,124
|
|
|
147,680
|
|
|
Matthew S. Ramsey
|
|
12/29/2016
|
|
95,625
|
|
|
3,424,331
|
|
|
|
|
12/9/2015
|
|
77,190
|
|
|
2,764,174
|
|
|
James M. Wright, Jr.
|
|
12/29/2016
|
|
23,906
|
|
|
856,074
|
|
|
|
|
12/9/2015
|
|
14,620
|
|
|
523,542
|
|
|
|
|
12/16/2014
|
|
9,104
|
|
|
326,014
|
|
|
|
|
12/30/2013
|
|
2,960
|
|
|
105,998
|
|
|
|
|
1/10/2013
|
|
2,400
|
|
|
85,944
|
|
|
Michael J. Hennigan
|
|
N/A
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|||
Sunoco Logistics Unit Awards:
|
|
|
|
|
|
|
|||
Thomas E. Long
|
|
12/29/2016
|
|
16,021
|
|
|
384,824
|
|
|
|
|
12/4/2015
|
|
11,208
|
|
|
269,216
|
|
|
Michael J. Hennigan
|
|
12/12/2016
|
|
133,508
|
|
|
3,206,862
|
|
|
|
|
12/4/2015
|
|
116,750
|
|
|
2,804,335
|
|
|
|
|
12/5/2014
|
|
74,043
|
|
|
1,778,513
|
|
|
|
|
1/29/2014
|
|
4,000
|
|
|
96,080
|
|
|
|
|
12/5/2013
|
|
34,960
|
|
|
839,739
|
|
|
|
|
1/24/2013
|
|
16,000
|
|
|
384,320
|
|
|
|
|
12/5/2012
|
|
36,000
|
|
|
864,720
|
|
|
|
|
|
|
|
|
|
|||
Sunoco LP Unit Awards:
|
|
|
|
|
|
|
|||
Thomas E. Long
|
|
12/29/2016
|
|
22,210
|
|
|
597,227
|
|
|
|
|
12/16/2015
|
|
14,125
|
|
|
379,821
|
|
|
Matthew S. Ramsey
|
|
1/2/2015
|
|
2,035
|
|
|
54,721
|
|
|
|
|
11/10/2014
|
|
747
|
|
|
20,087
|
|
(1)
|
ETP common unit awards outstanding vest as follows:
|
•
|
at a rate of 60% in December 2019 and 40% in December 2021 for awards granted in December 2016;
|
•
|
at a rate of 60% in December 2018 and 40% in December 2020 for awards granted in December 2015;
|
•
|
at a rate of 60% in December 2017 and 40% in December 2019 for awards granted in December 2014;
|
•
|
at a rate of 60% in December 2016 and 40% in December 2018 for awards granted in December 2013;
|
•
|
at a rate of 60% in December 2015 and 40% in December 2017 for awards granted in January 2013; and
|
•
|
ratably in December of each year through 2017 for awards granted in December 2012.
|
•
|
at a rate of 60% in December 2019 and 40% in December 2021 for awards granted in December 2016;
|
•
|
at a rate of 60% in December 2018 and 40% in December 2020 for awards granted in December 2015;
|
•
|
at a rate of 60% in December 2017 and 40% in December 2019 for awards granted in December 2014;
|
•
|
at a rate of 60% in December 2016 and 40% in December 2018 for awards granted in January 2014 and awards granted in December 2013; and
|
•
|
ratably in December of each year through 2017 for awards granted in January 2013 and December 2012.
|
•
|
at a rate of 60% in December 2019 and 40% in December 2021 for awards granted in December 2016;
|
•
|
at a rate of 60% in December 2018 and 40% in December 2020 for awards granted in December 2015; and
|
•
|
at a rate of 60% in December 2017 and 40% in December 2019 for awards granted in November 2014 and January 2015.
|
(2)
|
Sunoco Logistics unit amounts reflect the two-for-one split of Sunoco Logistics common units in June 2014.
|
(3)
|
Market value was computed as the number of unvested awards as of
December 31, 2016
multiplied by the closing price of our Common Units or Sunoco Logistics or Sunoco LP common units, accordingly, on
December 31, 2016
.
|
(4)
|
Upon the April 30, 2015 Regency Merger, each outstanding unvested Regency unit award converted into
0.4124
ETP unit awards, maintaining the same terms as the original Regency award terms, which were similar to those of ETP. These outstanding unit awards represent Regency awards that converted to ETP awards.
|
|
|
Unit Awards
|
|||||
Name
|
|
Number of Units Acquired on Vesting
(1)(2)
(#)
|
|
Value Realized on Vesting
(1)
($)
|
|||
ETP Unit Awards:
|
|
|
|
|
|||
Kelcy L. Warren
|
|
—
|
|
|
$
|
—
|
|
Thomas E. Long
|
|
8,372
|
|
|
294,937
|
|
|
Matthew S. Ramsey
|
|
—
|
|
|
—
|
|
|
James M. Wright, Jr.
|
|
6,040
|
|
|
212,783
|
|
|
Michael J. Hennigan
|
|
—
|
|
|
—
|
|
|
Sunoco Logistics Unit Awards:
|
|
|
|
|
|||
Michael J. Hennigan
|
|
110,440
|
|
|
2,559,999
|
|
(1)
|
Amounts presented represent the number of units subject to awards that vested during
2016
and the value realized upon vesting of such units, which is calculated as the number of units subject to vesting multiplied by the closing price of our Common Units or Sunoco Logistics common units, accordingly, upon the vesting date.
|
(2)
|
Sunoco Logistics unit amounts reflect the two-for-one split of Sunoco Logistics common units in June 2014.
|
Name
|
|
Executive Contributions in Last FY
($)
|
|
Registrant Contributions in Last FY
($)
|
|
Aggregate Earnings in
Last FY
($)
|
|
Aggregate Withdrawals/Distributions
($)
|
|
Aggregate Balance at Last FYE
($)
|
||||||||||
Kelcy L. Warren
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Thomas E. Long
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Matthew S. Ramsey
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
James M. Wright, Jr.
|
|
—
|
|
|
—
|
|
|
47,766
|
|
|
—
|
|
|
73,467
|
|
|||||
Michael J. Hennigan
|
|
—
|
|
|
—
|
|
|
360,066
|
|
|
—
|
|
|
3,682,582
|
|
Name
|
|
Fees Paid in Cash
(1)
($)
|
|
Unit Awards
(2)
($)
|
|
All Other Compensation
($)
|
|
Total
($)
|
||||||||
Ted Collins, Jr.
|
|
$
|
87,852
|
|
|
$
|
100,001
|
|
|
$
|
—
|
|
|
$
|
187,853
|
|
Michael K. Grimm
|
|
132,352
|
|
|
100,001
|
|
|
—
|
|
|
232,353
|
|
||||
James R. (Rick) Perry
(3)
|
|
118,411
|
|
|
100,001
|
|
|
—
|
|
|
218,412
|
|
||||
David K. Skidmore
|
|
128,865
|
|
|
100,001
|
|
|
—
|
|
|
228,866
|
|
(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 Common Units as of the grant date.
|
(3)
|
Mr. Perry resigned from the board of our General Partner effective December 31, 2016, at which time all of his unit awards were forfeited. In January 2017, the ETP Compensation Committee approved a cash payment to Mr. Perry of $191,870, representing the fair value of the unit awards forfeited upon his resignation.
|
Plan Category
|
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
(a)
|
|
Weighted-average exercise price of outstanding options, warrants and rights
(b)
|
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column
(a)
)
(c)
|
||||
Equity compensation plans approved by security holders
|
|
6,291,137
|
|
|
$
|
—
|
|
|
1,819,381
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
6,291,137
|
|
|
$
|
—
|
|
|
1,819,381
|
|
Title of Class
|
|
Name and Address of Beneficial Owner
(1)
|
|
Beneficially Owned
(2)(3)
|
|
Percent of Class
|
||
Common Units
|
|
Kelcy L. Warren
|
|
21,107
|
|
|
*
|
|
|
|
Thomas E. Long
|
|
27,340
|
|
|
*
|
|
|
|
Marshall S. (Mackie) McCrea, III
|
|
351,710
|
|
|
*
|
|
|
|
Matthew S. Ramsey
|
|
15,355
|
|
|
*
|
|
|
|
James M. Wright, Jr.
|
|
16,884
|
|
|
*
|
|
|
|
Michael J. Hennigan
|
|
—
|
|
|
*
|
|
|
|
A. Troy Sturrock
|
|
10,391
|
|
|
*
|
|
|
|
Ted Collins, Jr.
|
|
114,624
|
|
|
*
|
|
|
|
Michael K. Grimm
|
|
34,158
|
|
|
*
|
|
|
|
David K. Skidmore
|
|
11,617
|
|
|
*
|
|
|
|
All Directors and Executive Officers as a Group (10 Persons)
|
|
603,186
|
|
|
*
|
|
|
|
ETE
(4)
|
|
18,356,751
|
|
|
3.3
|
%
|
|
|
ALPS Advisors, Inc.
(5)
|
|
27,621,824
|
|
|
5.0
|
%
|
Class E Units
|
|
Heritage Holdings, Inc.
(6)
|
|
8,853,832
|
|
|
100
|
%
|
Class G Units
|
|
Sunoco, Inc.
(7)
|
|
90,706,000
|
|
|
100
|
%
|
Class H Units
|
|
ETE
(4)
|
|
81,001,069
|
|
|
100
|
%
|
Class K Units
|
|
Sunoco, Inc.
(7)
|
|
64,102,567
|
|
|
100
|
%
|
Class K Units
|
|
ETP Holdco
|
|
19,509,477
|
|
|
100
|
%
|
Class K Units
|
|
SUG Holdings
|
|
17,913,385
|
|
|
100
|
%
|
*
|
Less than 1%
|
(1)
|
Unless otherwise indicated, the address for all beneficial owners listed above is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225. The address for Mr. McCrea is 800 E. Sonterra Blvd., San Antonio, Texas 78258. The address for Mr. Hennigan
|
(2)
|
Beneficial ownership for the purposes of the foregoing table is defined by Rule 13d-3 under the Exchange Act. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty (60) days.
|
(3)
|
Due to the ownership by certain officers and directors of the general partner of ETE of equity interests in ETE (either directly or through one or more entities) and due to their positions as directors of the general partner of ETE, they may be deemed to beneficially own the limited partnership interests held by ETE, to the extent of their respective interests therein. Any such deemed ownership is not reflected in the table.
|
(4)
|
ETE owns all member interests of Energy Transfer Partners, L.L.C and all of the Class A limited partner interests and Class B limited partner interests in Energy Transfer Partners GP, L.P. Energy Transfer Partners, L.L.C. is the general partner of Energy Transfer Partners GP, L.P. with a 0.01% general partner interest. LE GP, LLC, the general partner of ETE, may be deemed to beneficially own the Common Units owned of record by ETE. The members of LE GP, LLC are Ray C. Davis and Kelcy L. Warren.
|
(5)
|
Information reflected herein for ALPS Advisors, Inc. (“AAI”) is based on its Schedule 13G filed on January 26, 2017. AAI, a registered investment adviser, furnishes investment advice to investment companies registered under the Investment Company Act of 1940 (collectively referred to as the “Funds”). In its role as investment advisor, AAI has voting and/or investment power over the ETP common units that are owned by the Funds, and may be deemed to be the beneficial owner of the ETP common units held by the Funds. However, all units reported in this table are owned by the Funds. AAI disclaims beneficial ownership of such common units. The Funds have the right to receive or the power to direct the receipt of dividends from, or the proceeds from the sale of ETP common units held in their respective accounts. Alerian MLP ETF is an investment company registered under the Investment Company Act of 1940 and is one of the Funds to which AAI provides investment advice. The interest of Alerian MLP ETF, as reported in its January 26, 2017 Schedule 13G, amounted to 27,505,142 common units, or 4.99% of the total outstanding ETP common units.
|
(6)
|
The Partnership indirectly owns 100% of the common stock of Heritage Holdings, Inc.
|
(7)
|
The Partnership indirectly owns 100% of the common stock of Sunoco, Inc.
|
|
Years Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
Audit fees
(1)
|
$
|
6.4
|
|
|
$
|
6.8
|
|
Audit related fees
(2)
|
0.4
|
|
|
0.8
|
|
||
Tax fees
(3)
|
0.1
|
|
|
0.1
|
|
||
Total
|
$
|
6.9
|
|
|
$
|
7.7
|
|
(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 2016 and 2015 for financial statement audits and interim reviews of subsidiary entities in connection with contribution and sale transactions. Includes fees in 2016 and 2015 in connection with the service organization control report on Panhandle’s centralized data center.
|
(3)
|
Includes fees 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.
|
(a)
|
The following documents are filed as a part of this Report:
|
(1)
|
Financial Statements – see
Index to Financial Statements
appearing on page
F-1
.
|
(2)
|
Financial Statement Schedules – None.
|
(3)
|
Exhibits – see
Index to Exhibits
set forth on page
E-1
.
|
ENERGY TRANSFER PARTNERS, 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 24, 2017
|
Kelcy L. Warren
|
|
of Directors (Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Thomas E. Long
|
|
Chief Financial Officer
|
|
February 24, 2017
|
Thomas E. Long
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ A. Troy Sturrock
|
|
Senior Vice President and Controller
|
|
February 24, 2017
|
A. Troy Sturrock
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Matthew S. Ramsey
|
|
President, Chief Operating Officer and Director
|
|
February 24, 2017
|
Matthew S. Ramsey
|
|
|
|
|
|
|
|
|
|
/s/ Marshall S. McCrea, III
|
|
Director
|
|
February 24, 2017
|
Marshall S. McCrea, III
|
|
|
|
|
|
|
|
|
|
/s/ Ted Collins, Jr.
|
|
Director
|
|
February 24, 2017
|
Ted Collins, Jr.
|
|
|
|
|
|
|
|
|
|
/s/ Michael K. Grimm
|
|
Director
|
|
February 24, 2017
|
Michael K. Grimm
|
|
|
|
|
|
|
|
|
|
/s/ David K. Skidmore
|
|
Director
|
|
February 24, 2017
|
David K. Skidmore
|
|
|
|
|
Exhibit Number
|
|
Description
|
2.1
|
|
Contribution and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. dated October 15, 2011 (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed October 18, 2011).
|
2.2
|
|
Amendment No. 1, dated December 1, 2011, to the Contribution and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. dated October 15, 2011 (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed December 7, 2011).
|
2.3
|
|
Amendment No. 2, dated January 11, 2012, to the Contribution and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. dated October 15, 2011 (incorporated by reference to Exhibit 10.1 to Exhibit 2.1 to Registrant’s Form 8-K filed on January 13, 2012).
|
2.4
|
|
Agreement and Plan of Merger, dated as of April 29, 2012 by and among Energy Transfer Partners, L.P., Sam Acquisition Corporation, Energy Transfer Partners GP, L.P., Sunoco, Inc. and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on May 1, 2012).
|
2.5
|
|
Amendment No. 1, dated as of June 15, 2012, to the Agreement and Plan of Merger, dated as of April 29, 2012, by and among Energy Transfer Partners, L.P., Sam Acquisition Corporation, Energy Transfer Partners GP, L.P., Sunoco, Inc., and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 to Registrant’s Form 8-K filed on June 20, 2012).
|
2.6
|
|
Transaction Agreement, dated as of June 15, 2012, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage Holdings, Inc., Energy Transfer Equity, L.P., ETE Sigma Holdco, LLC and ETE Holdco Corporation (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on June 20, 2012).
|
2.7
|
|
Agreement and Plan of Merger, dated as of April 27, 2014 by and among Energy Transfer Partners, L.P., Drive Acquisition Corporation, Heritage Holdings, Inc., Energy Transfer Partners GP, L.P., Susser Holdings Corporation, and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on April 28, 2014).
|
2.8
|
|
Agreement and Plan of Merger, dated as of January 25, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Regency Energy Partners LP, Regency GP LP and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on January 26, 2015).
|
2.9
|
|
Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Rendezvous I LLC, Rendezvous II LLC, Regency Energy Partners LP, Regency GP LP, ETE GP Acquirer LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 to Registrant’s Form 8-K filed on February 19, 2015).
|
2.10
|
|
Contribution Agreement, dated October 24, 2016 by and among Energy Transfer Partners, L.P. and NGP X US Holdings, LP, PennTex Midstream Partners, LLC, MRD Midstream LLC, WHR Midstream LLC and certain individual investors and managers named therein (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed October 25, 2016).
|
2.11
|
|
Membership Interest Purchase Agreement, dated as of August 2, 2016, by and between Bakken Holdings Company LLC and MarEn Bakken Company LLC (incorporated by reference to Exhibit 2.2 to the Registrant’s Form 10-Q for the quarter ended September 30, 2016).
|
2.12*
|
|
First Amendment, dated December 14, 2016, to the Membership Interest Purchase Agreement, dated as of August 2, 2016, by and between Bakken Holdings Company LLC and MarEn Bakken Company LLC.
|
2.13
|
|
Agreement and Plan of Merger, dated as of November 20, 2016, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Sunoco Logistics Partners L.P., Sunoco Partners LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporate by reference to Exhibit 2.1 of Form 8-K File No. 1-11727, filed November 21, 2016.
|
2.14
|
|
Amendment No. 1 to Agreement and Plan of Merger, dated as of December 16, 2016, by and among Sunoco Logistics Partners L.P., Sunoco Partners LLC, SXL Acquisition Sub LLC, SXL Acquisition Sub LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETP Acquisition Sub, LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporate by reference to Exhibit 2.2 of Form 8-K File No. 1-11727, filed December 21, 2016.
|
Exhibit Number
|
|
Description
|
3.1
|
|
Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.) dated as of July 28, 2009 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed July 29, 2009).
|
3.1.1
|
|
Amendment No. 1, dated March 26, 2012, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated July 28, 2009 (incorporated by reference to Exhibit 3.1 to Registrant’s Form 8-K filed on March 28, 2012).
|
3.1.2
|
|
Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated October 5, 2012 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed October 5, 2012).
|
3.1.3
|
|
Amendment No. 3, dated April 15, 2013, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K/A filed on April 18, 2013).
|
3.1.4
|
|
Amendment No. 4, dated April 30, 2013, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed on May 1, 2013).
|
3.1.5
|
|
Amendment No. 5, dated October 31, 2013, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed on November 1, 2013).
|
3.1.6
|
|
Amendment No. 6, dated February 19, 2014, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed on February 19, 2014).
|
3.1.7
|
|
Amendment No. 7, dated March 3, 2014, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated July 28, 2009 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed on March 5, 2014).
|
3.1.8
|
|
Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated August 29, 2014 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed on August 29, 2014).
|
3.1.9
|
|
Amendment No. 9, dated March 9, 2015, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed March 10, 2015).
|
3.1.10
|
|
Amendment No. 10 to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed April 30, 2015).
|
3.1.11
|
|
Amendment No. 11 to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. dated as of August 21, 2015 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed August 27, 2015).
|
3.1.12
|
|
Amendment No. 12 to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated as of April 6, 2016 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed April 7, 2016).
|
3.1.13
|
|
Amendment No. 13 to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated July 27, 2016 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed August 2, 2016).
|
3.1.14
|
|
Amendment No. 14 to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated November 1, 2016 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed November 3, 2016).
|
3.1.15
|
|
Amendment No. 15 to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated December 29, 2016 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed January 4, 2017).
|
3.2
|
|
Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 3.3 to the Registrant’s Form 10-Q for the quarter ended February 29, 2004).
|
3.3
|
|
Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.5 to the Registrant’s Form 10-Q for the quarter ended May 31, 2007).
|
3.3.1
|
|
Amendment No. 2, dated March 26, 2012, to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P., dated as of April 17, 2007 (incorporated by reference to Exhibit 3.2 to Registrant’s Form 8-K filed on March 28, 2012).
|
3.4
|
|
Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed August 10, 2010).
|
Exhibit Number
|
|
Description
|
3.4.1
|
|
Amendment No. 1, dated March 26, 2012, to the Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C., dated as of August 10, 2010 (incorporated by reference to Exhibit 3.3 to Registrant’s Form 8-K filed on March 28, 2012).
|
3.5
|
|
Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 to Form S-1, File No. 333-71968, filed October 22, 2001).
|
3.5.1
|
|
Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of August 28, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed September 1, 2015).
|
3.6
|
|
Certificate of Limited Partnership of Sunoco Logistics Operations L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1, File No. 333-71968, filed December 18, 2001).
|
3.7
|
|
First Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners Operations L.P., dated as of February 8, 2002 (incorporated by reference to Exhibit 3.5 of Form 10-K, File No. 1-31219, filed April 1, 2002).
|
3.8
|
|
Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of January 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed January 28, 2010).
|
3.8.1
|
|
Amendment No. 1 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of July 1, 2011 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed July 5, 2011).
|
3.8.2
|
|
Amendment No. 2 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of November 21, 2011 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed November 28, 2011).
|
3.8.3
|
|
Amendment No. 3 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of June 12, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed June 17, 2014).
|
3.8.4
|
|
Amendment No. 4 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of July 30, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed August 4, 2014).
|
3.8.5
|
|
Amendment No. 5 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of August 28, 2015 (incorporated by reference to Exhibit 3.2 of Form 8-K, File No. 1-31219, filed September 1, 2015).
|
3.8.6
|
|
Amendment No. 6 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of October 8, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed October 15, 2015).
|
3.8.7
|
|
Amendment No. 7 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of September 26, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed September 26, 2016).
|
3.9
|
|
Fifth Amended and Restated Limited Liability Company Agreement of Sunoco Partners LLC dated as of October 21, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed November 1, 2013).
|
3.10
|
|
Certificate of Formation of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13 to the Registrant’s Form 10-Q for the quarter ended March 31, 2010).
|
3.10.1
|
|
Certificate of Amendment of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13.1 to the Registrant’s Form 10-Q for the quarter ended March 31, 2010).
|
3.11
|
|
Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.14 to the Registrant’s Form 10-Q for the quarter ended March 31, 2010).
|
4.1
|
|
Registration Rights Agreement, dated April 30, 2013, by and between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed on May 1, 2013).
|
4.2
|
|
Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed January 19, 2005).
|
4.3
|
|
First Supplemental Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of the Registrant’s Form 8-K filed on January 19, 2005).
|
Exhibit Number
|
|
Description
|
4.4
|
|
Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (Incorporated by reference to Exhibit 10.45 to the Registrant’s Form 10-Q for the quarter ended February 28, 2005).
|
4.5
|
|
Form of Senior Indenture of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 4.11 to the Registrant’s Form S-3 filed August 9, 2006).
|
4.6
|
|
Form of Subordinated Indenture of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 4.12to the Registrant’s Form S-3 filed August 9, 2006).
|
4.7
|
|
Fourth Supplemental Indenture dated as of June 29, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P, the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.13 to the Registrant’s Form 10-K for the year ended August 31, 2006).
|
4.8
|
|
Fifth Supplemental Indenture dated as of October 23, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P, the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed October 25, 2006).
|
4.9
|
|
Sixth Supplemental Indenture dated March 28, 2008, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed March 31, 2008).
|
4.10
|
|
Seventh Supplemental Indenture dated December 23, 2008, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed December 23, 2008).
|
4.10.1
|
|
Eighth Supplemental Indenture dated April 7, 2009, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of the Registrant’s Form 8-K filed on April 7, 2009).
|
4.11
|
|
Ninth Supplemental Indenture, dated as of May 12, 2011, to the Indenture dated January 18, 2005, by and between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed May 12, 2011).
|
4.12
|
|
Tenth Supplemental Indenture, dated as of January 17, 2012, to the Indenture dated January 18, 2005, by and between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 1.1 to the Registrant’s Form 8-K filed January 17, 2012).
|
4.13
|
|
Eleventh Supplemental Indenture dated as of January 22, 2013 by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed January 22, 2013).
|
4.14
|
|
Twelfth Supplemental Indenture dated as of January 24, 2013 by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed June 26, 2013).
|
4.15
|
|
Thirteenth Supplemental Indenture dated as of September 19, 2013 by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed September 19, 2013).
|
4.16
|
|
Fourteenth Supplemental Indenture dated as of March 12, 2015 by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed on March 12, 2015).
|
4.17
|
|
Fifteenth Supplemental Indenture dated as of June 23, 2015 by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.3 to the Registrant’s Form 8-K filed June 23, 2015).
|
4.18
|
|
Indenture, dated as of March 31 2009, between Sunoco, Inc. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed October 5, 2012).
|
4.19
|
|
First Supplemental Indenture, dated as of March 31, 2009, between Sunoco, Inc. and U.S. Bank National Association, as trustee, to the Indenture, dated as of March 31, 2009, relating to Sunoco, Inc.’s 9.625% Senior Notes due 2015 (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed October 5, 2012).
|
4.20
|
|
Second Supplemental Indenture, dated as of October 5, 2012, among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National Association, as trustee, to Indenture, dated as of March 31, 2009 (incorporated by reference to Exhibit 4.3 to the Registrant’s Form 8-K filed October 5, 2012).
|
4.21
|
|
Indenture, dated as of June 30, 2000, between Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A. (incorporated by reference to Exhibit 4.4 to the Registrant’s Form 8-K filed October 5, 2012).
|
Exhibit Number
|
|
Description
|
4.22
|
|
First Supplemental Indenture, dated as of October 5, 2012, among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A., to the Indenture, dated as of June 30, 2000 (incorporated by reference to Exhibit 4.7 to the Registrant’s Form 8-K filed October 5, 2012).
|
4.23
|
|
Indenture, dated as of May 15, 1994, between Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A., relating to Sunoco, Inc.’s 9.00% Debentures due 2024 (incorporated by reference to Exhibit 4.8 to the Registrant’s Form 8-K filed October 5, 2012).
|
4.24
|
|
First Supplemental Indenture, dated as of October 5, 2012, among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A., to the Indenture, dated as of May 15, 1994 (incorporated by reference to Exhibit 4.9 to the Registrant’s Form 8-K filed October 5, 2012).
|
10.1+
|
|
Second Amended and Restated Energy Transfer Partners, L.P. 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit A to the Registrant’s Definitive Proxy Statement on Schedule 14A filed October 24, 2014).
|
10.2+
|
|
Energy Transfer Partners, L.P. Amended and Restated 2004 Unit Plan (incorporated by reference to Exhibit 10.6.6 to the Registrant’s Form 10-Q for the quarter ended June 30, 2008).
|
10.3+
|
|
Energy Transfer Partners Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended March 31, 2010).
|
10.4+
|
|
Form of Grant Agreement under the Energy Transfer Partners, L.P. Amended and Restated 2004 Unit Plan and the 2008 Energy Transfer Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed November 1, 2004).
|
10.5+
|
|
Energy Transfer Partners, L.L.C. Annual Bonus Plan effective January 1, 2014 (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 10-Q for the quarter ended June 30, 2014).
|
10.6
|
|
First Amendment, dated April 30, 2013, to the Services Agreement, effective as of May 26, 2010, by and among Energy Transfer Equity, L.P., ETE Services Company LLC and Regency Energy Partners LP (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 2013).
|
10.7
|
|
Guarantee of Collection, dated as of April 30, 2013, by and between Regency Energy Partners LP, PEPL Holdings, LLC and Regency Energy Finance Corp. (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 10-Q for the quarter ended June 30, 2013).
|
10.8
|
|
Second Amendment, dated April 30, 2013, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 10-Q for the quarter ended June 30, 2013).
|
10.9
|
|
Third Amendment, dated February 19, 2014, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010 and April 30, 2013 by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on February 19, 2014).
|
10.10
|
|
Exchange and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC dated August 7, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended September 30, 2013).
|
10.11
|
|
Cushion Gas Litigation Agreement, dated January 26, 2005, by and among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and La Grange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed February 1, 2005).
|
10.12
|
|
Purchase and Sale Agreement, dated as of September 14, 2006, among Energy Transfer Partners, L.P. and EFS-PA, LLC (a/k/a GE Energy Financial Services), CDPQ Investments (U.S.), Inc., Lake Bluff, Inc., Merrill Lynch Ventures, L.P. and Kings Road Holdings I, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed September 18, 2006).
|
10.13
|
|
Note Purchase Agreement, dated as of November 17, 2004, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2007).
|
10.13.1
|
|
Amendment No. 1 to the Note Purchase Agreement, dated as of April 18, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2007).
|
10.14
|
|
Note Purchase Agreement, dated as of May 24, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2007).
|
10.14.1
|
|
Note Purchase Agreement, dated December 9, 2009, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed December 14, 2009).
|
Exhibit Number
|
|
Description
|
10.15
|
|
Term Loan Agreement dated as of July 28, 2011, by and among Fayetteville Express Pipeline LLC, The Royal Bank of Scotland plc, as administrative agent, and certain other agents and lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed August 2, 2011).
|
10.16
|
|
Second Amended and Restated Credit Agreement dated as of October 27, 2011 among Energy Transfer Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and an LC Issuer, the other lenders party thereto and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and RBS Securities Inc., as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed November 2, 2011).
|
10.17
|
|
First Amendment, dated as of November 19, 2013, to Second Amended and Restated Credit Agreement, dated October 27, 2011 among Energy Transfer Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and an LC Issuer, the other lenders party thereto and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and RBS Securities Inc., as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed November 20, 2013).
|
10.18
|
|
Guarantee of Collection made as of March 26, 2012, by Citrus ETP Finance LLC, to Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on March 28, 2012).
|
10.19
|
|
Support Agreement, dated March 26, 2012, by and among PEPL Holdings, LLC, Energy Transfer Partners, L.P., and Citrus ETP Finance LLC (incorporated by reference to Exhibit 10.2 to Registrant’s Form 8-K filed on March 28, 2012).
|
10.20
|
|
Contingent Residual Support Agreement by and among Energy Transfer Partners, L.P., AmeriGas Finance LLC, AmeriGas Finance Corp., AmeriGas Partners, L.P. and, for certain limited purposes, UGI Corporation, dated January 12, 2012 (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on January 13, 2012).
|
10.21
|
|
Unitholder Agreement by and among Energy Transfer Equity, L.P., Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. dated January 12, 2012 (incorporated by reference to Exhibit 10.2 to Registrant’s Form 8-K filed on January 13, 2012).
|
10.22
|
|
Letter agreement by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P, dated January 11, 2012 (incorporated by reference to Exhibit 10.3 to Registrant’s Form 8-K filed on January 13, 2012).
|
10.23
|
|
Letter Agreement, dated as of April 29, 2012, by and among Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on May 1, 2012).
|
10.24
|
|
Commitment Increase Agreement by and among Energy Transfer Partners, L.P., the lenders party thereto and Wells Fargo Bank, National Association, in its capacity as administrative agent for the lenders dated as of February 10, 2015 (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed February 17, 2015).
|
10.25
|
|
Amended and Restated Operating Agreement of Sunoco, LLC, dated effective as of April 1, 2015, by and between ETP Retail Holdings, LLC and Susser Petroleum Operating Company LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed April 1, 2015).
|
10.26
|
|
Guarantee of Collection, made as of April 1, 2015, by ETP Retail Holdings, LLC to Sunoco LP and Sunoco Finance Corp. (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed on April 1, 2015).
|
10.27
|
|
Support Agreement, made as of April 1, 2015, by and among Sunoco, Inc. (R&M), Sunoco LP, Sunoco Finance Corp. and ETP Retail Holdings, LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed April 1, 2015).
|
10.28
|
|
Support Agreement, made as of April 1, 2015, by and among Atlantic Refining & Marketing Corp., Sunoco LP, Sunoco Finance Corp. and ETP Retail Holdings, LLC (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed April 1, 2015).
|
10.29
|
|
Eleventh Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed April 30, 2015).
|
10.30
|
|
Ninth Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed April 30, 2015).
|
10.31
|
|
Sixth Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, as guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed April 30, 2015).
|
Exhibit Number
|
|
Description
|
10.32
|
|
Eighth Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed April 30, 2015).
|
10.33
|
|
Second Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.5 to the Registrant’s Form 8-K filed April 30, 2015).
|
10.34
|
|
Separation and Non-Solicit Agreement and Full Release of Claims (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed May 14, 2015).
|
10.35
|
|
Seventh Supplemental Indenture, dated as of May 28, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, Energy Transfer Partners, L.P., as co-obligor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed June 1, 2015).
|
10.36
|
|
Twelfth Supplemental Indenture, dated as of August 10, 2015, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to the Registrant's Form 8-K filed August 13, 2015).
|
10.37
|
|
Eighth Supplemental Indenture, dated as of August 10, 2015, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.2 to the Registrant's Form 8-K filed August 13, 2015).
|
10.38
|
|
Ninth Supplemental Indenture, dated as of August 10, 2015, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 to the Registrant's Form 8-K filed August 13, 2015).
|
10.39
|
|
Contribution Agreement, dated as of July 14, 2015, by and among Susser Holdings Corporation, Heritage Holdings, Inc., ETP Holdco Corporation, Sunoco LP, Sunoco GP LLC and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 to the Registrant's Form 8-K filed July 15, 2015).
|
10.40
|
|
Exchange and Repurchase Agreement, dated as of July 14, 2015, by and among Energy Transfer Equity, L.P., Energy Transfer Partners GP, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.2 to the Registrant's Form 8-K filed July 15, 2015).
|
10.41
|
|
Contribution Agreement dated as of November 15, 2015, by and among Sunoco, LLC, Sunoco, Inc., ETP Retail Holdings, LLC, Sunoco LP, Sunoco GP LLC, and solely with respect to Section 11.19 and other provisions related thereto, Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 to the Registrant's Form 8-K filed November 19, 2015).
|
10.42+
|
|
Energy Transfer Partners Deferred Compensation Plan for Former Sunoco Executives effective October 5, 2012 (incorporated by reference to Exhibit 10.21 of the Form 10-K of Sunoco Logistics Partners L.P., File No. 1-31219, filed February 25, 2016).
|
10.43
|
|
Guarantee of Collection, dated as of March 31, 2016, by and between ETP Retail Holdings, LLC and Sunoco LP (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed April 1, 2016).
|
10.44
|
|
Support Agreement, dated as of March 31, 2016, by and between Sunoco, Inc., Sunoco LP, and ETP Retail Holdings, LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed April 1, 2016).
|
10.45
|
|
Support Agreement, dated as of March 31, 2016, by and between Atlantic Refining & Marketing Corp., Sunoco LP, and ETP Retail Holdings, LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed April 1, 2016).
|
10.46
|
|
Form of Commercial Paper Dealer Agreement between Energy Transfer Partners, L.P., as Issuer, and the Dealer party thereto (incorporated by reference to Exhibit 99.1 to the Registrant’s Form 8-K filed August 22, 2016).
|
12.1*
|
|
Computation of Ratio of Earnings to Fixed Charges.
|
21.1*
|
|
List of Subsidiaries.
|
23.1*
|
|
Consent of Grant Thornton LLP.
|
31.1*
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
31.2*
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
32.1**
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
32.2**
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
Exhibit Number
|
|
Description
|
101*
|
|
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014; (ii) our Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013; (iii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2015, 2014 and 2013; (iv) our Consolidated Statement of Partners’ Capital for the years ended December 31, 2015, 2014 and 2013; (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013; and (vi) the notes to our Consolidated Financial Statements.
|
*
|
|
Filed herewith.
|
**
|
|
Furnished herewith.
|
+
|
|
Denotes a management contract or compensatory plan or arrangement.
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
360
|
|
|
$
|
527
|
|
Accounts receivable, net
|
3,002
|
|
|
2,118
|
|
||
Accounts receivable from related companies
|
209
|
|
|
268
|
|
||
Inventories
|
1,712
|
|
|
1,213
|
|
||
Derivative assets
|
20
|
|
|
40
|
|
||
Other current assets
|
426
|
|
|
532
|
|
||
Total current assets
|
5,729
|
|
|
4,698
|
|
||
|
|
|
|
||||
Property, plant and equipment
|
58,220
|
|
|
50,869
|
|
||
Accumulated depreciation and depletion
|
(7,303
|
)
|
|
(5,782
|
)
|
||
|
50,917
|
|
|
45,087
|
|
||
|
|
|
|
||||
Advances to and investments in unconsolidated affiliates
|
4,280
|
|
|
5,003
|
|
||
Other non-current assets, net
|
672
|
|
|
536
|
|
||
Intangible assets, net
|
4,696
|
|
|
4,421
|
|
||
Goodwill
|
3,897
|
|
|
5,428
|
|
||
Total assets
|
$
|
70,191
|
|
|
$
|
65,173
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
2,900
|
|
|
$
|
1,859
|
|
Accounts payable to related companies
|
43
|
|
|
25
|
|
||
Derivative liabilities
|
166
|
|
|
63
|
|
||
Accrued and other current liabilities
|
1,905
|
|
|
2,048
|
|
||
Current maturities of long-term debt
|
1,189
|
|
|
126
|
|
||
Total current liabilities
|
6,203
|
|
|
4,121
|
|
||
|
|
|
|
||||
Long-term debt, less current maturities
|
31,741
|
|
|
28,553
|
|
||
Long-term notes payable – related company
|
250
|
|
|
233
|
|
||
Non-current derivative liabilities
|
76
|
|
|
137
|
|
||
Deferred income taxes
|
4,394
|
|
|
4,082
|
|
||
Other non-current liabilities
|
952
|
|
|
968
|
|
||
|
|
|
|
||||
Commitments and contingencies
|
|
|
|
||||
Series A Preferred Units
|
33
|
|
|
33
|
|
||
Redeemable noncontrolling interests
|
15
|
|
|
15
|
|
||
|
|
|
|
||||
Equity:
|
|
|
|
||||
General Partner
|
206
|
|
|
306
|
|
||
Limited Partners:
|
|
|
|
||||
Common Unitholders (529,869,235 and 505,645,703 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively)
|
14,946
|
|
|
17,043
|
|
||
Class E Unitholders (8,853,832 units authorized, issued and outstanding – held by subsidiary)
|
—
|
|
|
—
|
|
||
Class G Unitholders (90,706,000 units authorized, issued and outstanding – held by subsidiary)
|
—
|
|
|
—
|
|
||
Class H Unitholders (81,001,069 units authorized, issued and outstanding as of December 31, 2016 and 2015)
|
3,480
|
|
|
3,469
|
|
||
Class I Unitholders (100 units authorized, issued and outstanding)
|
2
|
|
|
14
|
|
||
Class K Unitholders (101,525,429 and 0 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively – held by subsidiary)
|
—
|
|
|
—
|
|
||
Accumulated other comprehensive income
|
8
|
|
|
4
|
|
||
Total partners’ capital
|
18,642
|
|
|
20,836
|
|
||
Noncontrolling interest
|
7,885
|
|
|
6,195
|
|
||
Total equity
|
26,527
|
|
|
27,031
|
|
||
Total liabilities and equity
|
$
|
70,191
|
|
|
$
|
65,173
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
REVENUES:
|
|
|
|
|
|
||||||
Natural gas sales
|
$
|
3,619
|
|
|
$
|
3,671
|
|
|
$
|
5,386
|
|
NGL sales
|
4,841
|
|
|
3,936
|
|
|
5,845
|
|
|||
Crude sales
|
6,766
|
|
|
8,378
|
|
|
16,416
|
|
|||
Gathering, transportation and other fees
|
4,003
|
|
|
3,997
|
|
|
3,517
|
|
|||
Refined product sales (see Note 3)
|
1,047
|
|
|
9,958
|
|
|
19,437
|
|
|||
Other (see Note 3)
|
1,551
|
|
|
4,352
|
|
|
4,874
|
|
|||
Total revenues
|
21,827
|
|
|
34,292
|
|
|
55,475
|
|
|||
COSTS AND EXPENSES:
|
|
|
|
|
|
||||||
Cost of products sold (see Note 3)
|
15,394
|
|
|
27,029
|
|
|
48,414
|
|
|||
Operating expenses (see Note 3)
|
1,484
|
|
|
2,261
|
|
|
2,059
|
|
|||
Depreciation, depletion and amortization
|
1,986
|
|
|
1,929
|
|
|
1,669
|
|
|||
Selling, general and administrative (see Note 3)
|
348
|
|
|
475
|
|
|
520
|
|
|||
Impairment losses
|
813
|
|
|
339
|
|
|
370
|
|
|||
Total costs and expenses
|
20,025
|
|
|
32,033
|
|
|
53,032
|
|
|||
OPERATING INCOME
|
1,802
|
|
|
2,259
|
|
|
2,443
|
|
|||
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
||||||
Interest expense, net
|
(1,317
|
)
|
|
(1,291
|
)
|
|
(1,165
|
)
|
|||
Equity in earnings from unconsolidated affiliates
|
59
|
|
|
469
|
|
|
332
|
|
|||
Impairment of investment in an unconsolidated affiliate
|
(308
|
)
|
|
—
|
|
|
—
|
|
|||
Gains on acquisitions
|
83
|
|
|
—
|
|
|
—
|
|
|||
Gain on sale of AmeriGas common units
|
—
|
|
|
—
|
|
|
177
|
|
|||
Losses on extinguishments of debt
|
—
|
|
|
(43
|
)
|
|
(25
|
)
|
|||
Losses on interest rate derivatives
|
(12
|
)
|
|
(18
|
)
|
|
(157
|
)
|
|||
Other, net
|
131
|
|
|
22
|
|
|
(12
|
)
|
|||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)
|
438
|
|
|
1,398
|
|
|
1,593
|
|
|||
Income tax expense (benefit) from continuing operations
|
(186
|
)
|
|
(123
|
)
|
|
358
|
|
|||
INCOME FROM CONTINUING OPERATIONS
|
624
|
|
|
1,521
|
|
|
1,235
|
|
|||
Income from discontinued operations
|
—
|
|
|
—
|
|
|
64
|
|
|||
NET INCOME
|
624
|
|
|
1,521
|
|
|
1,299
|
|
|||
Less: Net income attributable to noncontrolling interest
|
327
|
|
|
157
|
|
|
116
|
|
|||
Less: Net loss attributable to predecessor
|
—
|
|
|
(34
|
)
|
|
(153
|
)
|
|||
NET INCOME ATTRIBUTABLE TO PARTNERS
|
297
|
|
|
1,398
|
|
|
1,336
|
|
|||
General Partner’s interest in net income
|
948
|
|
|
1,064
|
|
|
513
|
|
|||
Class H Unitholder’s interest in net income
|
351
|
|
|
258
|
|
|
217
|
|
|||
Class I Unitholder’s interest in net income
|
8
|
|
|
94
|
|
|
—
|
|
|||
Common Unitholders’ interest in net income (loss)
|
$
|
(1,010
|
)
|
|
$
|
(18
|
)
|
|
$
|
606
|
|
INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT:
|
|
|
|
|
|
||||||
Basic
|
$
|
(2.06
|
)
|
|
$
|
(0.09
|
)
|
|
$
|
1.58
|
|
Diluted
|
$
|
(2.06
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
1.58
|
|
NET INCOME (LOSS) PER COMMON UNIT:
|
|
|
|
|
|
||||||
Basic
|
$
|
(2.06
|
)
|
|
$
|
(0.09
|
)
|
|
$
|
1.77
|
|
Diluted
|
$
|
(2.06
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
1.77
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Net income
|
$
|
624
|
|
|
$
|
1,521
|
|
|
$
|
1,299
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
||||||
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges
|
—
|
|
|
—
|
|
|
3
|
|
|||
Change in value of available-for-sale securities
|
2
|
|
|
(3
|
)
|
|
1
|
|
|||
Actuarial gain (loss) relating to pension and other postretirement benefits
|
(1
|
)
|
|
65
|
|
|
(113
|
)
|
|||
Foreign currency translation adjustment
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|||
Change in other comprehensive income from unconsolidated affiliates
|
4
|
|
|
(1
|
)
|
|
(6
|
)
|
|||
|
4
|
|
|
60
|
|
|
(117
|
)
|
|||
Comprehensive income
|
628
|
|
|
1,581
|
|
|
1,182
|
|
|||
Less: Comprehensive income attributable to noncontrolling interest
|
327
|
|
|
157
|
|
|
116
|
|
|||
Less: Comprehensive loss attributable to predecessor
|
—
|
|
|
(34
|
)
|
|
(153
|
)
|
|||
Comprehensive income attributable to partners
|
$
|
301
|
|
|
$
|
1,458
|
|
|
$
|
1,219
|
|
|
|
|
Limited Partners
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
|
General
Partner
|
|
Common
Unitholders
|
|
Class H Units
|
|
Class I Units
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Noncontrolling
Interest
|
|
Predecessor Equity
|
|
Total
|
||||||||||||||||
Balance, December 31, 2013
|
$
|
171
|
|
|
$
|
9,797
|
|
|
$
|
1,511
|
|
|
$
|
—
|
|
|
$
|
61
|
|
|
$
|
3,780
|
|
|
$
|
3,374
|
|
|
$
|
18,694
|
|
Distributions to partners
|
(500
|
)
|
|
(1,252
|
)
|
|
(212
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,964
|
)
|
||||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(241
|
)
|
|
—
|
|
|
(241
|
)
|
||||||||
Units issued for cash
|
—
|
|
|
1,382
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,382
|
|
||||||||
Subsidiary units issued for cash
|
1
|
|
|
174
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,069
|
|
|
—
|
|
|
1,244
|
|
||||||||
Capital contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
67
|
|
|
—
|
|
|
67
|
|
||||||||
Lake Charles LNG Transaction
|
—
|
|
|
(1,167
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,167
|
)
|
||||||||
Susser Merger
|
—
|
|
|
908
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
626
|
|
|
—
|
|
|
1,534
|
|
||||||||
Sunoco Logistics acquisition of a noncontrolling interest
|
(1
|
)
|
|
(79
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(245
|
)
|
|
—
|
|
|
(325
|
)
|
||||||||
Predecessor distributions to partners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(645
|
)
|
|
(645
|
)
|
||||||||
Predecessor units issued for cash
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,227
|
|
|
1,227
|
|
||||||||
Predecessor equity issued for acquisitions, net of cash received
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,281
|
|
|
4,281
|
|
||||||||
Other comprehensive loss, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(117
|
)
|
|
—
|
|
|
—
|
|
|
(117
|
)
|
||||||||
Other, net
|
—
|
|
|
61
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(19
|
)
|
|
4
|
|
|
42
|
|
||||||||
Net income (loss)
|
513
|
|
|
606
|
|
|
217
|
|
|
—
|
|
|
—
|
|
|
116
|
|
|
(153
|
)
|
|
1,299
|
|
||||||||
Balance, December 31, 2014
|
184
|
|
|
10,430
|
|
|
1,512
|
|
|
—
|
|
|
(56
|
)
|
|
5,153
|
|
|
8,088
|
|
|
25,311
|
|
||||||||
Distributions to partners
|
(944
|
)
|
|
(1,863
|
)
|
|
(247
|
)
|
|
(80
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,134
|
)
|
||||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(338
|
)
|
|
—
|
|
|
(338
|
)
|
||||||||
Units issued for cash
|
—
|
|
|
1,428
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,428
|
|
||||||||
Subsidiary units issued for cash
|
2
|
|
|
298
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,219
|
|
|
—
|
|
|
1,519
|
|
||||||||
Capital contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
875
|
|
|
—
|
|
|
875
|
|
||||||||
Bakken Pipeline Transaction
|
—
|
|
|
(999
|
)
|
|
1,946
|
|
|
—
|
|
|
—
|
|
|
72
|
|
|
—
|
|
|
1,019
|
|
||||||||
Sunoco LP Exchange Transaction
|
—
|
|
|
(52
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(940
|
)
|
|
—
|
|
|
(992
|
)
|
||||||||
Susser Exchange Transaction
|
—
|
|
|
(68
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(68
|
)
|
||||||||
Acquisition and disposition of noncontrolling interest
|
—
|
|
|
(26
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39
|
)
|
|
—
|
|
|
(65
|
)
|
||||||||
Predecessor distributions to partners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(202
|
)
|
|
(202
|
)
|
||||||||
Predecessor units issued for cash
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|
34
|
|
||||||||
Regency Merger
|
—
|
|
|
7,890
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,890
|
)
|
|
—
|
|
||||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60
|
|
|
—
|
|
|
—
|
|
|
60
|
|
||||||||
Other, net
|
—
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
36
|
|
|
4
|
|
|
63
|
|
Net income (loss)
|
1,064
|
|
|
(18
|
)
|
|
258
|
|
|
94
|
|
|
—
|
|
|
157
|
|
|
(34
|
)
|
|
1,521
|
|
||||||||
Balance, December 31, 2015
|
$
|
306
|
|
|
$
|
17,043
|
|
|
$
|
3,469
|
|
|
$
|
14
|
|
|
$
|
4
|
|
|
$
|
6,195
|
|
|
$
|
—
|
|
|
$
|
27,031
|
|
Distributions to partners
|
(1,048
|
)
|
|
(2,134
|
)
|
|
(340
|
)
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,542
|
)
|
||||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(481
|
)
|
|
—
|
|
|
(481
|
)
|
||||||||
Units issued for cash
|
—
|
|
|
1,098
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,098
|
|
||||||||
Subsidiary units issued
|
—
|
|
|
37
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,351
|
|
|
—
|
|
|
1,388
|
|
||||||||
Capital contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
236
|
|
|
—
|
|
|
236
|
|
||||||||
Sunoco, Inc. retail business to Sunoco LP transaction
|
—
|
|
|
(405
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(405
|
)
|
||||||||
PennTex Acquisition
|
—
|
|
|
307
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
236
|
|
|
—
|
|
|
543
|
|
||||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||||||
Other, net
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
31
|
|
||||||||
Net income (loss)
|
948
|
|
|
(1,010
|
)
|
|
351
|
|
|
8
|
|
|
—
|
|
|
327
|
|
|
—
|
|
|
624
|
|
||||||||
Balance, December 31, 2016
|
$
|
206
|
|
|
$
|
14,946
|
|
|
$
|
3,480
|
|
|
$
|
2
|
|
|
$
|
8
|
|
|
$
|
7,885
|
|
|
$
|
—
|
|
|
$
|
26,527
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
OPERATING ACTIVITIES:
|
|
|
|
|
|
||||||
Net income
|
$
|
624
|
|
|
$
|
1,521
|
|
|
$
|
1,299
|
|
Reconciliation of net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
1,986
|
|
|
1,929
|
|
|
1,669
|
|
|||
Deferred income taxes
|
(169
|
)
|
|
202
|
|
|
(49
|
)
|
|||
Amortization included in interest expense
|
(20
|
)
|
|
(36
|
)
|
|
(60
|
)
|
|||
Inventory valuation adjustments
|
(170
|
)
|
|
104
|
|
|
473
|
|
|||
Unit-based compensation expense
|
80
|
|
|
79
|
|
|
68
|
|
|||
Impairment losses
|
813
|
|
|
339
|
|
|
370
|
|
|||
Gains on acquisitions
|
(83
|
)
|
|
—
|
|
|
—
|
|
|||
Gain on sale of AmeriGas common units
|
—
|
|
|
—
|
|
|
(177
|
)
|
|||
Losses on extinguishments of debt
|
—
|
|
|
43
|
|
|
25
|
|
|||
Impairment of investment in an unconsolidated affiliate
|
308
|
|
|
—
|
|
|
—
|
|
|||
Distributions on unvested awards
|
(25
|
)
|
|
(16
|
)
|
|
(16
|
)
|
|||
Equity in earnings of unconsolidated affiliates
|
(59
|
)
|
|
(469
|
)
|
|
(332
|
)
|
|||
Distributions from unconsolidated affiliates
|
406
|
|
|
440
|
|
|
291
|
|
|||
Other non-cash
|
(271
|
)
|
|
(22
|
)
|
|
(72
|
)
|
|||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations
|
(117
|
)
|
|
(1,367
|
)
|
|
(320
|
)
|
|||
Net cash provided by operating activities
|
3,303
|
|
|
2,747
|
|
|
3,169
|
|
|||
INVESTING ACTIVITIES:
|
|
|
|
|
|
||||||
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction
|
2,200
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from Bakken Pipeline Transaction
|
—
|
|
|
980
|
|
|
—
|
|
|||
Proceeds from Susser Exchange Transaction
|
—
|
|
|
967
|
|
|
—
|
|
|||
Proceeds from sale of noncontrolling interest
|
—
|
|
|
64
|
|
|
—
|
|
|||
Proceeds from the sale of AmeriGas common units
|
—
|
|
|
—
|
|
|
814
|
|
|||
Cash paid for Vitol Acquisition, net of cash received
|
(769
|
)
|
|
—
|
|
|
—
|
|
|||
Cash paid for PennTex Acquisition, net of cash received
|
(299
|
)
|
|
—
|
|
|
—
|
|
|||
Cash transferred to ETE in connection with the Sunoco LP Exchange
|
—
|
|
|
(114
|
)
|
|
—
|
|
|||
Cash paid for acquisition of a noncontrolling interest
|
—
|
|
|
(129
|
)
|
|
(325
|
)
|
|||
Cash paid for Susser Merger, net of cash received
|
—
|
|
|
—
|
|
|
(808
|
)
|
|||
Cash paid for predecessor acquisitions, net of cash received
|
—
|
|
|
—
|
|
|
(762
|
)
|
|||
Cash paid for all other acquisitions
|
(159
|
)
|
|
(675
|
)
|
|
(472
|
)
|
|||
Capital expenditures, excluding allowance for equity funds used during construction
|
(7,550
|
)
|
|
(9,098
|
)
|
|
(5,213
|
)
|
|||
Contributions in aid of construction costs
|
71
|
|
|
80
|
|
|
45
|
|
|||
Contributions to unconsolidated affiliates
|
(59
|
)
|
|
(45
|
)
|
|
(399
|
)
|
|||
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
135
|
|
|
124
|
|
|
136
|
|
|||
Proceeds from sale of discontinued operations
|
—
|
|
|
—
|
|
|
77
|
|
|||
Proceeds from the sale of assets
|
25
|
|
|
23
|
|
|
61
|
|
|||
Change in restricted cash
|
14
|
|
|
19
|
|
|
172
|
|
|||
Other
|
1
|
|
|
(16
|
)
|
|
(18
|
)
|
|||
Net cash used in investing activities
|
(6,390
|
)
|
|
(7,820
|
)
|
|
(6,692
|
)
|
|||
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
||||||
Proceeds from borrowings
|
19,916
|
|
|
22,462
|
|
|
15,354
|
|
|||
Repayments of long-term debt
|
(15,799
|
)
|
|
(17,843
|
)
|
|
(12,702
|
)
|
|||
Proceeds from affiliate notes
|
4,997
|
|
|
233
|
|
|
—
|
|
|||
Repayments on affiliate notes
|
(4,873
|
)
|
|
—
|
|
|
—
|
|
|||
Units issued for cash
|
1,098
|
|
|
1,428
|
|
|
1,382
|
|
|||
Subsidiary units issued for cash
|
1,388
|
|
|
1,519
|
|
|
1,244
|
|
|||
Predecessor units issued for cash
|
—
|
|
|
34
|
|
|
1,227
|
|
|||
Capital contributions from noncontrolling interest
|
236
|
|
|
841
|
|
|
67
|
|
|||
Distributions to partners
|
(3,542
|
)
|
|
(3,134
|
)
|
|
(1,964
|
)
|
|||
Predecessor distributions to partners
|
—
|
|
|
(202
|
)
|
|
(645
|
)
|
|||
Distributions to noncontrolling interest
|
(481
|
)
|
|
(338
|
)
|
|
(241
|
)
|
|||
Debt issuance costs
|
(22
|
)
|
|
(63
|
)
|
|
(63
|
)
|
|||
Other
|
2
|
|
|
—
|
|
|
(41
|
)
|
|||
Net cash provided by financing activities
|
2,920
|
|
|
4,937
|
|
|
3,618
|
|
|||
Increase (decrease) in cash and cash equivalents
|
(167
|
)
|
|
(136
|
)
|
|
95
|
|
|||
Cash and cash equivalents, beginning of period
|
527
|
|
|
663
|
|
|
568
|
|
|||
Cash and cash equivalents, end of period
|
$
|
360
|
|
|
$
|
527
|
|
|
$
|
663
|
|
1.
|
OPERATIONS AND BASIS OF PRESENTATION:
|
2.
|
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Accounts receivable
|
$
|
(919
|
)
|
|
$
|
819
|
|
|
$
|
600
|
|
Accounts receivable from related companies
|
30
|
|
|
(243
|
)
|
|
(22
|
)
|
|||
Inventories
|
(368
|
)
|
|
(351
|
)
|
|
51
|
|
|||
Other current assets
|
83
|
|
|
(178
|
)
|
|
150
|
|
|||
Other non-current assets, net
|
(78
|
)
|
|
188
|
|
|
(6
|
)
|
|||
Accounts payable
|
972
|
|
|
(1,215
|
)
|
|
(851
|
)
|
|||
Accounts payable to related companies
|
29
|
|
|
(160
|
)
|
|
3
|
|
|||
Accrued and other current liabilities
|
39
|
|
|
(83
|
)
|
|
(191
|
)
|
|||
Other non-current liabilities
|
33
|
|
|
(219
|
)
|
|
(73
|
)
|
|||
Price risk management assets and liabilities, net
|
62
|
|
|
75
|
|
|
19
|
|
|||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations
|
$
|
(117
|
)
|
|
$
|
(1,367
|
)
|
|
$
|
(320
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
NON-CASH INVESTING ACTIVITIES:
|
|
|
|
|
|
||||||
Accrued capital expenditures
|
$
|
822
|
|
|
$
|
896
|
|
|
$
|
643
|
|
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP
|
194
|
|
|
—
|
|
|
—
|
|
|||
Net gains from subsidiary common unit transactions
|
37
|
|
|
300
|
|
|
175
|
|
|||
NON-CASH FINANCING ACTIVITIES:
|
|
|
|
|
|
||||||
Issuance of Common Units in connection with the PennTex Acquisition
|
$
|
307
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Issuance of Common Units in connection with the Regency Merger
|
—
|
|
|
9,250
|
|
|
—
|
|
|||
Issuance of Class H Units in connection with the Bakken Pipeline Transaction
|
—
|
|
|
1,946
|
|
|
—
|
|
|||
Issuance of Common Units in connection with the Susser Merger
|
—
|
|
|
—
|
|
|
908
|
|
|||
Contribution of property, plant and equipment from noncontrolling interest
|
—
|
|
|
34
|
|
|
—
|
|
|||
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions
|
—
|
|
|
—
|
|
|
564
|
|
|||
Predecessor equity issuances of common units in connection with Regency’s acquisitions
|
—
|
|
|
—
|
|
|
4,281
|
|
|||
Long-term debt assumed or exchanged in Regency’s acquisitions
|
—
|
|
|
—
|
|
|
2,386
|
|
|||
Redemption of Common Units in connection with the Bakken Pipeline Transaction
|
—
|
|
|
999
|
|
|
—
|
|
|||
Redemption of Common Units in connection with the Sunoco LP Exchange
|
—
|
|
|
52
|
|
|
—
|
|
|||
Redemption of Common Units in connection with the Lake Charles LNG Transaction
|
—
|
|
|
—
|
|
|
1,167
|
|
|||
SUPPLEMENTAL CASH FLOW INFORMATION:
|
|
|
|
|
|
||||||
Cash paid for interest, net of interest capitalized
|
$
|
1,411
|
|
|
$
|
1,467
|
|
|
$
|
1,232
|
|
Cash paid for (refund of) income taxes
|
(229
|
)
|
|
71
|
|
|
344
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Natural gas and NGLs
|
$
|
699
|
|
|
$
|
415
|
|
Crude oil
|
683
|
|
|
424
|
|
||
Refined products
|
113
|
|
|
104
|
|
||
Spare parts and other
|
217
|
|
|
270
|
|
||
Total inventories
|
$
|
1,712
|
|
|
$
|
1,213
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Deposits paid to vendors
|
$
|
74
|
|
|
$
|
74
|
|
Income taxes receivable
|
128
|
|
|
291
|
|
||
Prepaid expenses and other
|
224
|
|
|
167
|
|
||
Total other current assets
|
$
|
426
|
|
|
$
|
532
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Land and improvements
|
$
|
659
|
|
|
$
|
686
|
|
Buildings and improvements (1 to 45 years)
|
1,784
|
|
|
1,526
|
|
||
Pipelines and equipment (5 to 83 years)
|
35,923
|
|
|
33,148
|
|
||
Natural gas and NGL storage facilities (5 to 46 years)
|
1,515
|
|
|
391
|
|
||
Bulk storage, equipment and facilities (2 to 83 years)
|
3,677
|
|
|
2,853
|
|
||
Retail equipment (2 to 99 years)
|
—
|
|
|
401
|
|
||
Vehicles (1 to 25 years)
|
241
|
|
|
220
|
|
||
Right of way (20 to 83 years)
|
3,374
|
|
|
2,573
|
|
||
Natural resources
|
434
|
|
|
484
|
|
||
Other (1 to 40 years)
|
517
|
|
|
743
|
|
||
Construction work-in-process
|
10,096
|
|
|
7,844
|
|
||
|
58,220
|
|
|
50,869
|
|
||
Less – Accumulated depreciation and depletion
|
(7,303
|
)
|
|
(5,782
|
)
|
||
Property, plant and equipment, net
|
$
|
50,917
|
|
|
$
|
45,087
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Depreciation and depletion expense
|
$
|
1,793
|
|
|
$
|
1,713
|
|
|
$
|
1,457
|
|
Capitalized interest, excluding AFUDC
|
200
|
|
|
163
|
|
|
101
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Unamortized financing costs
(1)
|
$
|
3
|
|
|
$
|
11
|
|
Regulatory assets
|
86
|
|
|
90
|
|
||
Deferred charges
|
217
|
|
|
198
|
|
||
Restricted funds
|
190
|
|
|
192
|
|
||
Long-term affiliated receivable
|
90
|
|
|
—
|
|
||
Other
|
86
|
|
|
45
|
|
||
Total other non-current assets, net
|
$
|
672
|
|
|
$
|
536
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||
|
Gross Carrying
Amount
|
|
Accumulated
Amortization
|
|
Gross Carrying
Amount
|
|
Accumulated
Amortization
|
||||||||
Amortizable intangible assets:
|
|
|
|
|
|
|
|
||||||||
Customer relationships, contracts and agreements (3 to 46 years)
|
$
|
5,362
|
|
|
$
|
(737
|
)
|
|
$
|
4,601
|
|
|
$
|
(554
|
)
|
Patents (10 years)
|
48
|
|
|
(21
|
)
|
|
48
|
|
|
(16
|
)
|
||||
Trade Names (20 years)
|
66
|
|
|
(22
|
)
|
|
66
|
|
|
(18
|
)
|
||||
Other (1 to 15 years)
|
2
|
|
|
(2
|
)
|
|
6
|
|
|
(3
|
)
|
||||
Total amortizable intangible assets
|
$
|
5,478
|
|
|
$
|
(782
|
)
|
|
$
|
4,721
|
|
|
$
|
(591
|
)
|
Non-amortizable intangible assets:
|
|
|
|
|
|
|
|
||||||||
Trademarks
|
—
|
|
|
—
|
|
|
291
|
|
|
—
|
|
||||
Total intangible assets
|
$
|
5,478
|
|
|
$
|
(782
|
)
|
|
$
|
5,012
|
|
|
$
|
(591
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Reported in depreciation, depletion and amortization
|
$
|
193
|
|
|
$
|
216
|
|
|
$
|
212
|
|
|
Intrastate
Transportation
and Storage
|
|
Interstate
Transportation and Storage
|
|
Midstream
|
|
Liquids Transportation and Services
|
|
Investment in Sunoco Logistics
|
|
All Other
|
|
Total
|
||||||||||||||
Balance, December 31, 2014
|
$
|
10
|
|
|
$
|
1,011
|
|
|
$
|
767
|
|
|
$
|
432
|
|
|
$
|
1,358
|
|
|
$
|
4,064
|
|
|
$
|
7,642
|
|
Reduction due to Sunoco LP deconsolidation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,018
|
)
|
|
(2,018
|
)
|
|||||||
Impaired
|
—
|
|
|
(99
|
)
|
|
—
|
|
|
(106
|
)
|
|
—
|
|
|
—
|
|
|
(205
|
)
|
|||||||
Other
|
—
|
|
|
—
|
|
|
(49
|
)
|
|
—
|
|
|
—
|
|
|
58
|
|
|
9
|
|
|||||||
Balance, December 31, 2015
|
10
|
|
|
912
|
|
|
718
|
|
|
326
|
|
|
1,358
|
|
|
2,104
|
|
|
5,428
|
|
|||||||
Acquired
|
—
|
|
|
—
|
|
|
177
|
|
|
—
|
|
|
251
|
|
|
—
|
|
|
428
|
|
|||||||
Reduction due to contribution of legacy Sunoco, Inc. retail business
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,289
|
)
|
|
(1,289
|
)
|
|||||||
Impaired
|
—
|
|
|
(638
|
)
|
|
(32
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(670
|
)
|
|||||||
Balance, December 31, 2016
|
$
|
10
|
|
|
$
|
274
|
|
|
$
|
863
|
|
|
$
|
326
|
|
|
$
|
1,609
|
|
|
$
|
815
|
|
|
$
|
3,897
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Interstate transportation and storage
|
$
|
54
|
|
|
$
|
58
|
|
Investment in Sunoco Logistics
|
88
|
|
|
88
|
|
||
All other
|
28
|
|
|
66
|
|
||
|
$
|
170
|
|
|
$
|
212
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Interest payable
|
$
|
440
|
|
|
$
|
425
|
|
Customer advances and deposits
|
56
|
|
|
95
|
|
||
Accrued capital expenditures
|
749
|
|
|
743
|
|
||
Accrued wages and benefits
|
212
|
|
|
218
|
|
||
Taxes payable other than income taxes
|
63
|
|
|
76
|
|
||
Exchanges payable
|
208
|
|
|
105
|
|
||
Other
|
177
|
|
|
386
|
|
||
Total accrued and other current liabilities
|
$
|
1,905
|
|
|
$
|
2,048
|
|
|
Fair Value Total
|
|
Fair Value Measurements at December 31, 2016
|
||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives:
|
|
|
|
|
|
|
|
||||||||
Natural Gas:
|
|
|
|
|
|
|
|
||||||||
Basis Swaps IFERC/NYMEX
|
$
|
14
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Swing Swaps IFERC
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
||||
Fixed Swaps/Futures
|
96
|
|
|
96
|
|
|
—
|
|
|
—
|
|
||||
Forward Physical Swaps
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
Power:
|
|
|
|
|
|
|
|
||||||||
Forwards
|
4
|
|
|
—
|
|
|
4
|
|
|
—
|
|
||||
Futures
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||
Options – Calls
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||
Natural Gas Liquids – Forwards/Swaps
|
233
|
|
|
233
|
|
|
—
|
|
|
—
|
|
||||
Refined Products – Futures
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||
Crude – Futures
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
|
||||
Total commodity derivatives
|
362
|
|
|
355
|
|
|
7
|
|
|
—
|
|
||||
Total assets
|
$
|
362
|
|
|
$
|
355
|
|
|
$
|
7
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Interest rate derivatives
|
$
|
(193
|
)
|
|
$
|
—
|
|
|
$
|
(193
|
)
|
|
$
|
—
|
|
Embedded derivatives in the ETP Preferred Units
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||
Commodity derivatives:
|
|
|
|
|
|
|
|
||||||||
Natural Gas:
|
|
|
|
|
|
|
|
||||||||
Basis Swaps IFERC/NYMEX
|
(11
|
)
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
||||
Swing Swaps IFERC
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
||||
Fixed Swaps/Futures
|
(149
|
)
|
|
(149
|
)
|
|
—
|
|
|
—
|
|
||||
Power:
|
|
|
|
|
|
|
|
||||||||
Forwards
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
||||
Futures
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
||||
Natural Gas Liquids – Forwards/Swaps
|
(273
|
)
|
|
(273
|
)
|
|
—
|
|
|
—
|
|
||||
Refined Products – Futures
|
(17
|
)
|
|
(17
|
)
|
|
—
|
|
|
—
|
|
||||
Crude – Futures
|
(13
|
)
|
|
(13
|
)
|
|
—
|
|
|
—
|
|
||||
Total commodity derivatives
|
(472
|
)
|
|
(464
|
)
|
|
(8
|
)
|
|
—
|
|
||||
Total liabilities
|
$
|
(666
|
)
|
|
$
|
(464
|
)
|
|
$
|
(201
|
)
|
|
$
|
(1
|
)
|
|
Fair Value Total
|
|
Fair Value Measurements at December 31, 2015
|
||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives:
|
|
|
|
|
|
|
|
||||||||
Natural Gas:
|
|
|
|
|
|
|
|
||||||||
Basis Swaps IFERC/NYMEX
|
$
|
16
|
|
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Swing Swaps IFERC
|
10
|
|
|
2
|
|
|
8
|
|
|
—
|
|
||||
Fixed Swaps/Futures
|
274
|
|
|
274
|
|
|
—
|
|
|
—
|
|
||||
Forward Physical Swaps
|
4
|
|
|
—
|
|
|
4
|
|
|
—
|
|
||||
Power:
|
|
|
|
|
|
|
|
||||||||
Forwards
|
22
|
|
|
—
|
|
|
22
|
|
|
—
|
|
||||
Futures
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
|
||||
Options – Puts
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||
Options – Calls
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||
Natural Gas Liquids – Forwards/Swaps
|
99
|
|
|
99
|
|
|
—
|
|
|
—
|
|
||||
Refined Products – Futures
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
|
||||
Crude – Futures
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
|
||||
Total commodity derivatives
|
448
|
|
|
414
|
|
|
34
|
|
|
—
|
|
||||
Total assets
|
$
|
448
|
|
|
$
|
414
|
|
|
$
|
34
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Interest rate derivatives
|
$
|
(171
|
)
|
|
$
|
—
|
|
|
$
|
(171
|
)
|
|
$
|
—
|
|
Embedded derivatives in the ETP Preferred Units
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
||||
Commodity derivatives:
|
|
|
|
|
|
|
|
||||||||
Natural Gas:
|
|
|
|
|
|
|
|
||||||||
Basis Swaps IFERC/NYMEX
|
(16
|
)
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
||||
Swing Swaps IFERC
|
(12
|
)
|
|
(2
|
)
|
|
(10
|
)
|
|
—
|
|
||||
Fixed Swaps/Futures
|
(203
|
)
|
|
(203
|
)
|
|
—
|
|
|
—
|
|
||||
Power:
|
|
|
|
|
|
|
|
||||||||
Forwards
|
(22
|
)
|
|
—
|
|
|
(22
|
)
|
|
—
|
|
||||
Futures
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
||||
Options – Puts
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
||||
Natural Gas Liquids – Forwards/Swaps
|
(89
|
)
|
|
(89
|
)
|
|
—
|
|
|
—
|
|
||||
Crude – Futures
|
(5
|
)
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
||||
Total commodity derivatives
|
(350
|
)
|
|
(318
|
)
|
|
(32
|
)
|
|
—
|
|
||||
Total liabilities
|
$
|
(526
|
)
|
|
$
|
(318
|
)
|
|
$
|
(203
|
)
|
|
$
|
(5
|
)
|
|
Unobservable Input
|
|
December 31, 2016
|
|
Embedded derivatives in the ETP Preferred Units
|
Credit Spread
|
|
5.12
|
%
|
|
Volatility
|
|
31.73
|
%
|
Balance, December 31, 2015
|
$
|
(5
|
)
|
Net unrealized gains included in other income (expense)
|
4
|
|
|
Balance, December 31, 2016
|
$
|
(1
|
)
|
3.
|
ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
|
|
|
At November 1, 2016
|
||
Total current assets
|
|
$
|
34
|
|
Property, plant and equipment
|
|
393
|
|
|
Goodwill
(1)
|
|
177
|
|
|
Intangible assets
|
|
446
|
|
|
|
|
1,050
|
|
|
|
|
|
||
Total current liabilities
|
|
6
|
|
|
Long-term debt, less current maturities
|
|
164
|
|
|
Other non-current liabilities
|
|
17
|
|
|
Noncontrolling interest
|
|
236
|
|
|
|
|
423
|
|
|
Total consideration
|
|
627
|
|
|
Cash received
|
|
21
|
|
|
Total consideration, net of cash received
|
|
$
|
606
|
|
(1)
|
None
of the goodwill is expected to be deductible for tax purposes.
|
|
Years Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
Revenues
|
$
|
12,482
|
|
|
$
|
22,487
|
|
Cost of products sold
|
11,174
|
|
|
21,155
|
|
||
Operating expenses
|
798
|
|
|
727
|
|
||
Selling, general and administrative expenses
|
106
|
|
|
99
|
|
|
|
Susser
|
||
Total current assets
|
|
$
|
446
|
|
Property, plant and equipment
|
|
1,069
|
|
|
Goodwill
(1)
|
|
1,734
|
|
|
Intangible assets
|
|
611
|
|
|
Other non-current assets
|
|
17
|
|
|
|
|
3,877
|
|
|
|
|
|
||
Total current liabilities
|
|
377
|
|
|
Long-term debt, less current maturities
|
|
564
|
|
|
Deferred income taxes
|
|
488
|
|
|
Other non-current liabilities
|
|
39
|
|
|
Noncontrolling interest
|
|
626
|
|
|
|
|
2,094
|
|
|
Total consideration
|
|
1,783
|
|
|
Cash received
|
|
67
|
|
|
Total consideration, net of cash received
|
|
$
|
1,716
|
|
(1)
|
None
of the goodwill is expected to be deductible for tax purposes.
|
Assets
|
At July 1, 2014
|
||
Current assets
|
$
|
120
|
|
Property, plant and equipment
|
1,295
|
|
|
Other non-current assets
|
4
|
|
|
Goodwill
|
49
|
|
|
Total assets acquired
|
1,468
|
|
|
Liabilities
|
|
||
Current liabilities
|
116
|
|
|
Long-term debt
|
499
|
|
|
Other non-current liabilities
|
12
|
|
|
Total liabilities assumed
|
627
|
|
|
|
|
||
Net assets acquired
|
$
|
841
|
|
Assets
|
At March 21, 2014
|
||
Current assets
|
$
|
149
|
|
Property, plant and equipment
|
2,716
|
|
|
Investment in unconsolidated affiliates
|
62
|
|
|
Intangible assets (average useful life of 30 years)
|
2,717
|
|
|
Goodwill
(1)
|
370
|
|
|
Other non-current assets
|
18
|
|
|
Total assets acquired
|
6,032
|
|
|
Liabilities
|
|
||
Current liabilities
|
168
|
|
|
Long-term debt
|
1,788
|
|
|
Premium related to senior notes
|
99
|
|
|
Non-current liabilities
|
30
|
|
|
Total liabilities assumed
|
2,085
|
|
|
Net assets acquired
|
$
|
3,947
|
|
4.
|
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Citrus
|
$
|
1,729
|
|
|
$
|
1,739
|
|
AmeriGas
|
82
|
|
|
80
|
|
||
FEP
|
101
|
|
|
115
|
|
||
MEP
|
318
|
|
|
660
|
|
||
HPC
|
382
|
|
|
402
|
|
||
Sunoco LP
|
1,225
|
|
|
1,380
|
|
||
Others
|
443
|
|
|
627
|
|
||
Total
|
$
|
4,280
|
|
|
$
|
5,003
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Current assets
|
$
|
2,109
|
|
|
$
|
1,646
|
|
Property, plant and equipment, net
|
13,355
|
|
|
12,611
|
|
||
Other assets
|
6,557
|
|
|
5,485
|
|
||
Total assets
|
$
|
22,021
|
|
|
$
|
19,742
|
|
|
|
|
|
||||
Current liabilities
|
$
|
2,547
|
|
|
$
|
1,517
|
|
Non-current liabilities
|
12,899
|
|
|
10,428
|
|
||
Equity
|
6,575
|
|
|
7,797
|
|
||
Total liabilities and equity
|
$
|
22,021
|
|
|
$
|
19,742
|
|
5.
|
NET INCOME (LOSS) PER LIMITED PARTNER UNIT:
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Income from continuing operations
|
$
|
624
|
|
|
$
|
1,521
|
|
|
$
|
1,235
|
|
Less: Income from continuing operations attributable to noncontrolling interest
|
327
|
|
|
157
|
|
|
116
|
|
|||
Less: Loss from continuing operations attributable to predecessor
|
—
|
|
|
(34
|
)
|
|
(153
|
)
|
|||
Income from continuing operations, net of noncontrolling interest
|
297
|
|
|
1,398
|
|
|
1,272
|
|
|||
General Partner’s interest in income from continuing operations
|
948
|
|
|
1,064
|
|
|
513
|
|
|||
Class H Unitholder’s interest in income from continuing operations
|
351
|
|
|
258
|
|
|
217
|
|
|||
Class I Unitholder’s interest in income from continuing operations
|
8
|
|
|
94
|
|
|
—
|
|
|||
Common Unitholders’ interest in income (loss) from continuing operations
|
(1,010
|
)
|
|
(18
|
)
|
|
542
|
|
|||
Additional earnings allocated to General Partner
|
(10
|
)
|
|
(5
|
)
|
|
(4
|
)
|
|||
Distributions on employee unit awards, net of allocation to General Partner
|
(19
|
)
|
|
(16
|
)
|
|
(13
|
)
|
|||
Income (loss) from continuing operations available to Common Unitholders
|
$
|
(1,039
|
)
|
|
$
|
(39
|
)
|
|
$
|
525
|
|
Weighted average Common Units – basic
|
505.5
|
|
|
432.8
|
|
|
331.5
|
|
|||
Basic income (loss) from continuing operations per Common Unit
|
$
|
(2.06
|
)
|
|
$
|
(0.09
|
)
|
|
$
|
1.58
|
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations available to Common Unitholders
|
$
|
(1,039
|
)
|
|
$
|
(39
|
)
|
|
$
|
525
|
|
Loss attributable to ETP Series A Preferred Units
|
—
|
|
|
(6
|
)
|
|
—
|
|
|||
|
$
|
(1,039
|
)
|
|
$
|
(45
|
)
|
|
$
|
525
|
|
Weighted average Common Units – basic
|
505.5
|
|
|
432.8
|
|
|
331.5
|
|
|||
Dilutive effect of unvested Unit Awards
|
—
|
|
|
—
|
|
|
1.3
|
|
|||
Dilutive effect of Preferred Units
|
—
|
|
|
0.7
|
|
|
—
|
|
|||
Weighted average Common Units – diluted
|
505.5
|
|
|
433.5
|
|
|
332.8
|
|
|||
Diluted income (loss) from continuing operations per Common Unit
|
$
|
(2.06
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
1.58
|
|
Basic income from discontinued operations per Common Unit
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.19
|
|
Diluted income from discontinued operations per Common Unit
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.19
|
|
6.
|
DEBT OBLIGATIONS:
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
ETP Debt
|
|
|
|
||||
6.125% Senior Notes due February 15, 2017
|
$
|
400
|
|
|
$
|
400
|
|
2.50% Senior Notes due June 15, 2018
|
650
|
|
|
650
|
|
||
6.70% Senior Notes due July 1, 2018
|
600
|
|
|
600
|
|
||
9.70% Senior Notes due March 15, 2019
|
400
|
|
|
400
|
|
||
9.00% Senior Notes due April 15, 2019
|
450
|
|
|
450
|
|
||
5.75% Senior Notes due September 1, 2020
|
400
|
|
|
400
|
|
||
4.15% Senior Notes due October 1, 2020
|
1,050
|
|
|
1,050
|
|
||
6.50% Senior Notes due July 15, 2021
|
500
|
|
|
500
|
|
4.65% Senior Notes due June 1, 2021
|
800
|
|
|
800
|
|
||
5.20% Senior Notes due February 1, 2022
|
1,000
|
|
|
1,000
|
|
||
5.875% Senior Notes due March 1, 2022
|
900
|
|
|
900
|
|
||
5.00% Senior Notes due October 1, 2022
|
700
|
|
|
700
|
|
||
3.60% Senior Notes due February 1, 2023
|
800
|
|
|
800
|
|
||
5.50% Senior Notes due April 15, 2023
|
700
|
|
|
700
|
|
||
4.50% Senior Notes due November 1, 2023
|
600
|
|
|
600
|
|
||
4.90% Senior Notes due February 1, 2024
|
350
|
|
|
350
|
|
||
7.60% Senior Notes due February 1, 2024
|
277
|
|
|
277
|
|
||
4.05% Senior Notes due March 15, 2025
|
1,000
|
|
|
1,000
|
|
||
4.75% Senior Notes due January 15, 2026
|
1,000
|
|
|
1,000
|
|
||
8.25% Senior Notes due November 15, 2029
|
267
|
|
|
267
|
|
||
4.90% Senior Notes due March 15, 2035
|
500
|
|
|
500
|
|
||
6.625% Senior Notes due October 15, 2036
|
400
|
|
|
400
|
|
||
7.50% Senior Notes due July 1, 2038
|
550
|
|
|
550
|
|
||
6.05% Senior Notes due June 1, 2041
|
700
|
|
|
700
|
|
||
6.50% Senior Notes due February 1, 2042
|
1,000
|
|
|
1,000
|
|
||
5.15% Senior Notes due February 1, 2043
|
450
|
|
|
450
|
|
||
5.95% Senior Notes due October 1, 2043
|
450
|
|
|
450
|
|
||
5.15% Senior Notes due March 15, 2045
|
1,000
|
|
|
1,000
|
|
||
6.125% Senior Notes due December 15, 2045
|
1,000
|
|
|
1,000
|
|
||
Floating Rate Junior Subordinated Notes due November 1, 2066
|
546
|
|
|
545
|
|
||
ETP $3.75 billion Revolving Credit Facility due November 2019
|
2,777
|
|
|
1,362
|
|
||
Unamortized premiums, discounts and fair value adjustments, net
|
(18
|
)
|
|
(21
|
)
|
||
Deferred debt issuance costs
|
(132
|
)
|
|
(147
|
)
|
||
|
22,067
|
|
|
20,633
|
|
||
Transwestern Debt
|
|
|
|
||||
5.54% Senior Notes due November 17, 2016
|
—
|
|
|
125
|
|
||
5.64% Senior Notes due May 24, 2017
|
82
|
|
|
82
|
|
||
5.36% Senior Notes due December 9, 2020
|
175
|
|
|
175
|
|
||
5.89% Senior Notes due May 24, 2022
|
150
|
|
|
150
|
|
||
5.66% Senior Notes due December 9, 2024
|
175
|
|
|
175
|
|
||
6.16% Senior Notes due May 24, 2037
|
75
|
|
|
75
|
|
||
Unamortized premiums, discounts and fair value adjustments, net
|
—
|
|
|
(1
|
)
|
||
Deferred debt issuance costs
|
(1
|
)
|
|
(2
|
)
|
||
|
656
|
|
|
779
|
|
||
Panhandle Debt
|
|
|
|
||||
6.20% Senior Notes due November 1, 2017
|
300
|
|
|
300
|
|
||
7.00% Senior Notes due June 15, 2018
|
400
|
|
|
400
|
|
||
8.125% Senior Notes due June 1, 2019
|
150
|
|
|
150
|
|
||
7.60% Senior Notes due February 1, 2024
|
82
|
|
|
82
|
|
||
7.00% Senior Notes due July 15, 2029
|
66
|
|
|
66
|
|
||
8.25% Senior Notes due November 15, 2029
|
33
|
|
|
33
|
|
||
Floating Rate Junior Subordinated Notes due November 1, 2066
|
54
|
|
|
54
|
|
||
Unamortized premiums, discounts and fair value adjustments, net
|
50
|
|
|
75
|
|
||
|
1,135
|
|
|
1,160
|
|
||
Sunoco, Inc. Debt
|
|
|
|
||||
5.75% Senior Notes due January 15, 2017
|
400
|
|
|
400
|
|
||
9.00% Debentures due November 1, 2024
|
65
|
|
|
65
|
|
||
Unamortized premiums, discounts and fair value adjustments, net
|
9
|
|
|
20
|
|
||
|
474
|
|
|
485
|
|
||
Sunoco Logistics Debt
|
|
|
|
||||
6.125% Senior Notes due May 15, 2016
|
—
|
|
|
175
|
|
||
5.50% Senior Notes due February 15, 2020
|
250
|
|
|
250
|
|
||
4.40% Senior Notes due April 1, 2021
|
600
|
|
|
600
|
|
||
4.65% Senior Notes due February 15, 2022
|
300
|
|
|
300
|
|
||
3.45% Senior Notes due January 15, 2023
|
350
|
|
|
350
|
|
||
4.25% Senior Notes due April 1, 2024
|
500
|
|
|
500
|
|
5.95% Senior Notes due December 1, 2025
|
400
|
|
|
400
|
|
||
3.90% Senior Notes due July 15, 2026
|
550
|
|
|
—
|
|
||
6.85% Senior Notes due February 15, 2040
|
250
|
|
|
250
|
|
||
6.10% Senior Notes due February 15, 2042
|
300
|
|
|
300
|
|
||
4.95% Senior Notes due January 15, 2043
|
350
|
|
|
350
|
|
||
5.30% Senior Notes due April 1, 2044
|
700
|
|
|
700
|
|
||
5.35% Senior Notes due May 15, 2045
|
800
|
|
|
800
|
|
||
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020
|
1,292
|
|
|
562
|
|
||
Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017
(1)
|
630
|
|
|
—
|
|
||
Unamortized premiums, discounts and fair value adjustments, net
|
75
|
|
|
85
|
|
||
Deferred debt issuance costs
|
(34
|
)
|
|
(32
|
)
|
||
|
7,313
|
|
|
5,590
|
|
||
Bakken Project Debt
|
|
|
|
||||
Bakken Project $2.50 billion Credit Facility due August 2019
|
1,100
|
|
|
—
|
|
||
Deferred debt issuance costs
|
(13
|
)
|
|
—
|
|
||
|
1,087
|
|
|
—
|
|
||
PennTex Debt
|
|
|
|
||||
PennTex $275 million Revolving Credit Facility due December 2019
|
168
|
|
|
—
|
|
||
|
|
|
|
||||
Other
|
30
|
|
|
32
|
|
||
|
32,930
|
|
|
28,679
|
|
||
Less: current maturities
|
1,189
|
|
|
126
|
|
||
|
$
|
31,741
|
|
|
$
|
28,553
|
|
(1)
|
Sunoco Logistics’
$1.0 billion
364-Day Credit Facility, including its
$630 million
term loan, were classified as long-term debt as of
December 31, 2016
as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis.
|
2017
|
|
$
|
1,812
|
|
2018
|
|
1,650
|
|
|
2019
|
|
5,045
|
|
|
2020
|
|
3,167
|
|
|
2021
|
|
1,900
|
|
|
Thereafter
|
|
19,420
|
|
|
Total
|
|
$
|
32,994
|
|
•
|
incur indebtedness;
|
•
|
grant liens;
|
•
|
enter into mergers;
|
•
|
dispose of assets;
|
•
|
make certain investments;
|
•
|
make Distributions (as defined in the ETP Credit Facility) during certain Defaults (as defined in the ETP Credit Facility) and during any Event of Default (as defined in the ETP Credit Facility);
|
•
|
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
|
•
|
engage in transactions with affiliates; and
|
•
|
enter into restrictive agreements.
|
•
|
prohibition of certain incremental secured indebtedness;
|
•
|
prohibition of certain liens / negative pledge;
|
•
|
limitations on uses of loan proceeds;
|
•
|
limitations on asset sales and purchases;
|
•
|
limitations on permitted business activities;
|
•
|
limitations on mergers and acquisitions;
|
•
|
limitations on investments;
|
•
|
limitations on transactions with affiliates; and
|
•
|
maintenance of commercially reasonable insurance coverage.
|
7.
|
SERIES A PREFERRED UNITS:
|
8.
|
EQUITY:
|
|
Years Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Number of Common Units, beginning of period
|
505.6
|
|
|
355.5
|
|
|
333.8
|
|
Common Units redeemed in connection with certain transactions
|
(17.8
|
)
|
|
(51.8
|
)
|
|
(18.7
|
)
|
Common Units issued in connection with certain acquisitions
|
8.9
|
|
|
172.2
|
|
|
15.8
|
|
Common Units issued in connection with the Distribution Reinvestment Plan
|
6.6
|
|
|
7.7
|
|
|
2.8
|
|
Common Units issued in connection with Equity Distribution Agreements
|
26.1
|
|
|
21.1
|
|
|
21.4
|
|
Issuance of Common Units under equity incentive plans
|
0.5
|
|
|
0.9
|
|
|
0.4
|
|
Number of Common Units, end of period
|
529.9
|
|
|
505.6
|
|
|
355.5
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2013
|
|
February 7, 2014
|
|
February 14, 2014
|
|
$
|
0.9200
|
|
March 31, 2014
|
|
May 5, 2014
|
|
May 15, 2014
|
|
0.9350
|
|
|
June 30, 2014
|
|
August 4, 2014
|
|
August 14, 2014
|
|
0.9550
|
|
|
September 30, 2014
|
|
November 3, 2014
|
|
November 14, 2014
|
|
0.9750
|
|
|
December 31, 2014
|
|
February 6, 2015
|
|
February 13, 2015
|
|
0.9950
|
|
|
March 31, 2015
|
|
May 8, 2015
|
|
May 15, 2015
|
|
1.0150
|
|
|
June 30, 2015
|
|
August 6, 2015
|
|
August 14, 2015
|
|
1.0350
|
|
|
September 30, 2015
|
|
November 5, 2015
|
|
November 16, 2015
|
|
1.0550
|
|
|
December 31, 2015
|
|
February 8, 2016
|
|
February 16, 2016
|
|
1.0550
|
|
|
March 31, 2016
|
|
May 6, 2016
|
|
May 16, 2016
|
|
1.0550
|
|
|
June 30, 2016
|
|
August 8, 2016
|
|
August 15, 2016
|
|
1.0550
|
|
|
September 30, 2016
|
|
November 7, 2016
|
|
November 14, 2016
|
|
1.0550
|
|
|
December 31, 2016
|
|
February 7, 2017
|
|
February 14, 2017
|
|
1.0550
|
|
|
|
Total Year
|
||
2017
|
|
$
|
626
|
|
2018
|
|
138
|
|
|
2019
|
|
128
|
|
|
Each year beyond 2019
|
|
33
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2013
|
|
February 10, 2014
|
|
February 14, 2014
|
|
$
|
0.3312
|
|
March 31, 2014
|
|
May 9, 2014
|
|
May 15, 2014
|
|
0.3475
|
|
|
June 30, 2014
|
|
August 8, 2014
|
|
August 14, 2014
|
|
0.3650
|
|
|
September 30, 2014
|
|
November 7, 2014
|
|
November 14, 2014
|
|
0.3825
|
|
|
December 31, 2014
|
|
February 9, 2015
|
|
February 13, 2015
|
|
0.4000
|
|
|
March 31, 2015
|
|
May 11, 2015
|
|
May 15, 2015
|
|
0.4190
|
|
|
June 30, 2015
|
|
August 10, 2015
|
|
August 14, 2015
|
|
0.4380
|
|
|
September 30, 2015
|
|
November 9, 2015
|
|
November 13, 2015
|
|
0.4580
|
|
|
December 31, 2015
|
|
February 8, 2016
|
|
February 12, 2016
|
|
0.4790
|
|
|
March 31, 2016
|
|
May 9, 2016
|
|
May 13, 2016
|
|
0.4890
|
|
|
June 30, 2016
|
|
August 8, 2016
|
|
August 12, 2016
|
|
0.5000
|
|
|
September 30, 2016
|
|
November 9, 2016
|
|
November 14, 2016
|
|
0.5100
|
|
|
December 31, 2016
|
|
February 7, 2017
|
|
February 14, 2017
|
|
0.5200
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
September 30, 2016
|
|
November 7, 2016
|
|
November 14, 2016
|
|
$
|
0.2950
|
|
December 31, 2016
|
|
February 7, 2017
|
|
February 14, 2017
|
|
0.2950
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Available-for-sale securities
|
$
|
2
|
|
|
$
|
—
|
|
Foreign currency translation adjustment
|
(5
|
)
|
|
(4
|
)
|
||
Actuarial gain related to pensions and other postretirement benefits
|
7
|
|
|
8
|
|
||
Investments in unconsolidated affiliates, net
|
4
|
|
|
—
|
|
||
Total AOCI, net of tax
|
$
|
8
|
|
|
$
|
4
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Available-for-sale securities
|
$
|
(2
|
)
|
|
$
|
(2
|
)
|
Foreign currency translation adjustment
|
3
|
|
|
4
|
|
||
Actuarial loss relating to pension and other postretirement benefits
|
—
|
|
|
7
|
|
||
Total
|
$
|
1
|
|
|
$
|
9
|
|
9.
|
UNIT-BASED COMPENSATION PLANS:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value Per Unit
|
|||
Unvested awards as of December 31, 2015
|
4.8
|
|
|
$
|
47.61
|
|
Awards granted
|
2.5
|
|
|
35.73
|
|
|
Awards vested
|
(0.8
|
)
|
|
53.22
|
|
|
Awards forfeited
|
(0.2
|
)
|
|
48.39
|
|
|
Unvested awards as of December 31, 2016
|
6.3
|
|
|
41.53
|
|
|
Number of Sunoco Logistics Units
|
|
Weighted Average Grant-Date Fair Value Per Sunoco Logistics Unit
|
|||
Unvested awards as of December 31, 2015
|
2.5
|
|
|
$
|
33.16
|
|
Awards granted
|
1.3
|
|
|
23.21
|
|
|
Awards vested
|
(0.5
|
)
|
|
34.19
|
|
|
Awards forfeited
|
(0.1
|
)
|
|
33.72
|
|
|
Unvested awards as of December 31, 2016
|
3.2
|
|
|
28.57
|
|
10.
|
INCOME TAXES:
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Current expense (benefit):
|
|
|
|
|
|
||||||
Federal
|
$
|
18
|
|
|
$
|
(274
|
)
|
|
$
|
321
|
|
State
|
(35
|
)
|
|
(51
|
)
|
|
86
|
|
|||
Total
|
(17
|
)
|
|
(325
|
)
|
|
407
|
|
|||
Deferred expense (benefit):
|
|
|
|
|
|
||||||
Federal
|
(173
|
)
|
|
231
|
|
|
(50
|
)
|
|||
State
|
4
|
|
|
(29
|
)
|
|
1
|
|
|||
Total
|
(169
|
)
|
|
202
|
|
|
(49
|
)
|
|||
Total income tax expense (benefit) from continuing operations
|
$
|
(186
|
)
|
|
$
|
(123
|
)
|
|
$
|
358
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Income tax expense at U.S. statutory rate of 35 percent
|
$
|
154
|
|
|
$
|
490
|
|
|
$
|
558
|
|
Increase (reduction) in income taxes resulting from:
|
|
|
|
|
|
||||||
Partnership earnings not subject to tax
|
(519
|
)
|
|
(515
|
)
|
|
(341
|
)
|
|||
Nondeductible goodwill included in the Lake Charles LNG Transaction
|
—
|
|
|
—
|
|
|
105
|
|
|||
Goodwill impairments
|
223
|
|
|
—
|
|
|
—
|
|
|||
State income taxes (net of federal income tax effects)
|
(17
|
)
|
|
(37
|
)
|
|
54
|
|
|||
Dividend Received Deduction
|
(15
|
)
|
|
(24
|
)
|
|
—
|
|
|||
Audit Settlement
|
—
|
|
|
(7
|
)
|
|
—
|
|
|||
Premium on debt retirement
|
—
|
|
|
—
|
|
|
(10
|
)
|
|||
Foreign
|
—
|
|
|
—
|
|
|
(8
|
)
|
|||
Other
|
(12
|
)
|
|
(30
|
)
|
|
—
|
|
|||
Income tax expense (benefit) from continuing operations
|
$
|
(186
|
)
|
|
$
|
(123
|
)
|
|
$
|
358
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Deferred income tax assets:
|
|
|
|
||||
Net operating losses and alternative minimum tax credit
|
$
|
380
|
|
|
$
|
155
|
|
Pension and other postretirement benefits
|
30
|
|
|
36
|
|
||
Long term debt
|
32
|
|
|
61
|
|
||
Other
|
84
|
|
|
142
|
|
||
Total deferred income tax assets
|
526
|
|
|
394
|
|
||
Valuation allowance
|
(118
|
)
|
|
(121
|
)
|
||
Net deferred income tax assets
|
$
|
408
|
|
|
$
|
273
|
|
|
|
|
|
||||
Deferred income tax liabilities:
|
|
|
|
||||
Properties, plants and equipment
|
$
|
(1,054
|
)
|
|
$
|
(1,305
|
)
|
Investment in unconsolidated affiliates
|
(3,728
|
)
|
|
(2,889
|
)
|
||
Trademarks
|
—
|
|
|
(112
|
)
|
||
Other
|
(20
|
)
|
|
(49
|
)
|
||
Total deferred income tax liabilities
|
(4,802
|
)
|
|
(4,355
|
)
|
||
Accumulated deferred income taxes
|
$
|
(4,394
|
)
|
|
$
|
(4,082
|
)
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Net deferred income tax liability, beginning of year
|
$
|
(4,082
|
)
|
|
$
|
(4,331
|
)
|
ETE Acquisition of general partner of Sunoco LP
|
—
|
|
|
490
|
|
||
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)
|
(460
|
)
|
|
—
|
|
||
Tax provision
|
169
|
|
|
(202
|
)
|
||
Other
|
(21
|
)
|
|
(39
|
)
|
||
Net deferred income tax liability, end of year
|
$
|
(4,394
|
)
|
|
$
|
(4,082
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Balance at beginning of year
|
$
|
610
|
|
|
$
|
440
|
|
|
$
|
429
|
|
Additions attributable to tax positions taken in the current year
|
8
|
|
|
—
|
|
|
20
|
|
|||
Additions attributable to tax positions taken in prior years
|
18
|
|
|
178
|
|
|
—
|
|
|||
Reduction attributable to tax positions taken in prior years
|
(20
|
)
|
|
—
|
|
|
(1
|
)
|
|||
Settlements
|
—
|
|
|
—
|
|
|
(5
|
)
|
|||
Lapse of statute
|
(1
|
)
|
|
(8
|
)
|
|
(3
|
)
|
|||
Balance at end of year
|
$
|
615
|
|
|
$
|
610
|
|
|
$
|
440
|
|
11.
|
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Rental expense
(1)
|
|
$
|
81
|
|
|
$
|
176
|
|
|
$
|
159
|
|
Less: Sublease rental income
|
|
(1
|
)
|
|
(16
|
)
|
|
(26
|
)
|
|||
Rental expense, net
|
|
$
|
80
|
|
|
$
|
160
|
|
|
$
|
133
|
|
(1)
|
Includes contingent rentals totaling
$26 million
and
$24 million
for the years ended
December 31, 2015
and
2014
, respectively.
|
Years Ending December 31:
|
|
||
2017
|
$
|
38
|
|
2018
|
30
|
|
|
2019
|
28
|
|
|
2020
|
28
|
|
|
2021
|
35
|
|
|
Thereafter
|
133
|
|
|
Future minimum lease commitments
|
292
|
|
|
Less: Sublease rental income
|
(14
|
)
|
|
Net future minimum lease commitments
|
$
|
278
|
|
•
|
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
|
•
|
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
|
•
|
Currently operating Sunoco, Inc. retail sites.
|
•
|
Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
|
•
|
Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of
December 31, 2016
, Sunoco, Inc. had been named as a PRP at approximately
50
identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Current
|
$
|
32
|
|
|
$
|
41
|
|
Non-current
|
313
|
|
|
326
|
|
||
Total environmental liabilities
|
$
|
345
|
|
|
$
|
367
|
|
12.
|
DERIVATIVE ASSETS AND LIABILITIES:
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||
|
Notional
Volume
|
|
Maturity
|
|
Notional
Volume
|
|
Maturity
|
||
Mark-to-Market Derivatives
|
|
|
|
|
|
|
|
||
(Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (MMBtu):
|
|
|
|
|
|
|
|
||
Fixed Swaps/Futures
|
(682,500
|
)
|
|
2017
|
|
(602,500
|
)
|
|
2016-2017
|
Basis Swaps IFERC/NYMEX
(1)
|
2,242,500
|
|
|
2017
|
|
(31,240,000
|
)
|
|
2016-2017
|
Power (Megawatt):
|
|
|
|
|
|
|
|
||
Forwards
|
391,880
|
|
|
2017-2018
|
|
357,092
|
|
|
2016-2017
|
Futures
|
109,564
|
|
|
2017-2018
|
|
(109,791
|
)
|
|
2016
|
Options – Puts
|
(50,400
|
)
|
|
2017
|
|
260,534
|
|
|
2016
|
Options – Calls
|
186,400
|
|
|
2017
|
|
1,300,647
|
|
|
2016
|
Crude (Bbls) – Futures
|
(617,000
|
)
|
|
2017
|
|
(591,000
|
)
|
|
2016-2017
|
(Non-Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (MMBtu):
|
|
|
|
|
|
|
|
||
Basis Swaps IFERC/NYMEX
|
10,750,000
|
|
|
2017-2018
|
|
(6,522,500
|
)
|
|
2016-2017
|
Swing Swaps IFERC
|
(5,662,500
|
)
|
|
2017
|
|
71,340,000
|
|
|
2016-2017
|
Fixed Swaps/Futures
|
(52,652,500
|
)
|
|
2017-2019
|
|
(14,380,000
|
)
|
|
2016-2018
|
Forward Physical Contracts
|
(22,492,489
|
)
|
|
2017
|
|
21,922,484
|
|
|
2016-2017
|
Natural Gas Liquid (Bbls) – Forwards/Swaps
|
(5,786,627
|
)
|
|
2017
|
|
(8,146,800
|
)
|
|
2016-2018
|
Refined Products (Bbls) – Futures
|
(2,240,000
|
)
|
|
2017
|
|
(939,000
|
)
|
|
2016-2017
|
Corn (Bushels) – Futures
|
—
|
|
|
—
|
|
1,185,000
|
|
|
2016
|
Fair Value Hedging Derivatives
|
|
|
|
|
|
|
|
||
(Non-Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (MMBtu):
|
|
|
|
|
|
|
|
||
Basis Swaps IFERC/NYMEX
|
(36,370,000
|
)
|
|
2017
|
|
(37,555,000
|
)
|
|
2016
|
Fixed Swaps/Futures
|
(36,370,000
|
)
|
|
2017
|
|
(37,555,000
|
)
|
|
2016
|
Hedged Item – Inventory
|
36,370,000
|
|
|
2017
|
|
37,555,000
|
|
|
2016
|
(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, 2016
|
|
December 31, 2015
|
||||||||
July 2016
(2)
|
|
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
|
|
$
|
—
|
|
|
$
|
200
|
|
July 2017
(3)
|
|
Forward-starting to pay a fixed rate of 3.90% and receive a floating rate
|
|
500
|
|
|
300
|
|
||
July 2018
(3)
|
|
Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
|
|
200
|
|
|
200
|
|
||
July 2019
(3)
|
|
Forward-starting to pay a fixed rate of 3.25% and receive a floating rate
|
|
200
|
|
|
200
|
|
||
December 2018
|
|
Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
|
|
1,200
|
|
|
1,200
|
|
||
March 2019
|
|
Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
|
|
300
|
|
|
300
|
|
(1)
|
Floating rates are based on 3-month LIBOR.
|
(2)
|
Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
|
(3)
|
Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
|
|
Fair Value of Derivative Instruments
|
||||||||||||||
|
Asset Derivatives
|
|
Liability Derivatives
|
||||||||||||
|
December 31, 2016
|
|
December 31, 2015
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives (margin deposits)
|
$
|
—
|
|
|
$
|
38
|
|
|
$
|
(4
|
)
|
|
$
|
(3
|
)
|
|
—
|
|
|
38
|
|
|
(4
|
)
|
|
(3
|
)
|
||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives (margin deposits)
|
338
|
|
|
353
|
|
|
(416
|
)
|
|
(306
|
)
|
||||
Commodity derivatives
|
24
|
|
|
57
|
|
|
(52
|
)
|
|
(41
|
)
|
||||
Interest rate derivatives
|
—
|
|
|
—
|
|
|
(193
|
)
|
|
(171
|
)
|
||||
Embedded derivatives in ETP Preferred Units
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(5
|
)
|
||||
|
362
|
|
|
410
|
|
|
(662
|
)
|
|
(523
|
)
|
||||
Total derivatives
|
$
|
362
|
|
|
$
|
448
|
|
|
$
|
(666
|
)
|
|
$
|
(526
|
)
|
|
Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
|
|
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
|
||||||||||
|
|
|
Years Ended December 31,
|
||||||||||
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Derivatives in cash flow hedging relationships:
|
|
|
|
|
|
|
|
||||||
Commodity derivatives
|
Cost of products sold
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
Total
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
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,
|
||||||||||
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Derivatives in fair value hedging relationships (including hedged item):
|
|
|
|
|
|
|
|
||||||
Commodity derivatives
|
Cost of products sold
|
|
$
|
14
|
|
|
$
|
21
|
|
|
$
|
(8
|
)
|
Total
|
|
|
$
|
14
|
|
|
$
|
21
|
|
|
$
|
(8
|
)
|
|
Location of Gain/(Loss) Recognized in Income on Derivatives
|
|
Amount of Gain (Loss) Recognized in Income on Derivatives
|
||||||||||
|
|
|
Years Ended December 31,
|
||||||||||
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||
Commodity derivatives – Trading
|
Cost of products sold
|
|
$
|
(35
|
)
|
|
$
|
(11
|
)
|
|
$
|
(6
|
)
|
Commodity derivatives – Non-trading
|
Cost of products sold
|
|
(173
|
)
|
|
23
|
|
|
199
|
|
|||
Interest rate derivatives
|
Losses on interest rate derivatives
|
|
(12
|
)
|
|
(18
|
)
|
|
(157
|
)
|
|||
Embedded derivatives
|
Other, net
|
|
4
|
|
|
12
|
|
|
3
|
|
|||
Total
|
|
|
$
|
(216
|
)
|
|
$
|
6
|
|
|
$
|
39
|
|
13.
|
RETIREMENT BENEFITS:
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||||||||||
|
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
|
$
|
20
|
|
|
$
|
57
|
|
|
$
|
180
|
|
|
$
|
718
|
|
|
$
|
65
|
|
|
$
|
202
|
|
Interest cost
|
1
|
|
|
2
|
|
|
4
|
|
|
23
|
|
|
2
|
|
|
4
|
|
||||||
Benefits paid, net
|
(1
|
)
|
|
(7
|
)
|
|
(21
|
)
|
|
(46
|
)
|
|
(8
|
)
|
|
(20
|
)
|
||||||
Actuarial (gain) loss and other
|
(2
|
)
|
|
(1
|
)
|
|
2
|
|
|
16
|
|
|
(2
|
)
|
|
(6
|
)
|
||||||
Settlements
|
—
|
|
|
—
|
|
|
—
|
|
|
(691
|
)
|
|
—
|
|
|
—
|
|
||||||
Benefit obligation at end of period
|
18
|
|
|
51
|
|
|
165
|
|
|
20
|
|
|
57
|
|
|
180
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Change in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fair value of plan assets at beginning of period
|
15
|
|
|
—
|
|
|
253
|
|
|
598
|
|
|
—
|
|
|
265
|
|
||||||
Return on plan assets and other
|
(2
|
)
|
|
—
|
|
|
6
|
|
|
16
|
|
|
—
|
|
|
—
|
|
||||||
Employer contributions
|
—
|
|
|
—
|
|
|
10
|
|
|
138
|
|
|
—
|
|
|
8
|
|
||||||
Benefits paid, net
|
(1
|
)
|
|
—
|
|
|
(21
|
)
|
|
(46
|
)
|
|
—
|
|
|
(20
|
)
|
||||||
Settlements
|
—
|
|
|
—
|
|
|
—
|
|
|
(691
|
)
|
|
—
|
|
|
—
|
|
||||||
Fair value of plan assets at end of period
|
12
|
|
|
—
|
|
|
248
|
|
|
15
|
|
|
—
|
|
|
253
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amount underfunded (overfunded) at end of period
|
$
|
6
|
|
|
$
|
51
|
|
|
$
|
(83
|
)
|
|
$
|
5
|
|
|
$
|
57
|
|
|
$
|
(73
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amounts recognized in the consolidated balance sheets consist of:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Non-current assets
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
108
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
97
|
|
Current liabilities
|
—
|
|
|
(7
|
)
|
|
(2
|
)
|
|
—
|
|
|
(9
|
)
|
|
(2
|
)
|
||||||
Non-current liabilities
|
(6
|
)
|
|
(44
|
)
|
|
(23
|
)
|
|
(5
|
)
|
|
(48
|
)
|
|
(22
|
)
|
||||||
|
$
|
(6
|
)
|
|
$
|
(51
|
)
|
|
$
|
83
|
|
|
$
|
(5
|
)
|
|
$
|
(57
|
)
|
|
$
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial gain
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(12
|
)
|
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
(17
|
)
|
Prior service cost
|
—
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
15
|
|
||||||
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
(2
|
)
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||||||||||
|
Pension Benefits
|
|
|
|
Pension Benefits
|
|
|
||||||||||||||||
|
Funded Plans
|
|
Unfunded Plans
|
|
Other Postretirement Benefits
|
|
Funded Plans
|
|
Unfunded Plans
|
|
Other Postretirement Benefits
|
||||||||||||
Projected benefit obligation
|
$
|
18
|
|
|
$
|
51
|
|
|
N/A
|
|
|
$
|
20
|
|
|
$
|
57
|
|
|
N/A
|
|
||
Accumulated benefit obligation
|
18
|
|
|
51
|
|
|
$
|
165
|
|
|
20
|
|
|
57
|
|
|
$
|
180
|
|
||||
Fair value of plan assets
|
12
|
|
|
—
|
|
|
248
|
|
|
15
|
|
|
—
|
|
|
253
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||
Net periodic benefit cost:
|
|
|
|
|
|
|
|
||||||||
Interest cost
|
$
|
3
|
|
|
$
|
4
|
|
|
$
|
25
|
|
|
$
|
4
|
|
Expected return on plan assets
|
(1
|
)
|
|
(8
|
)
|
|
(16
|
)
|
|
(8
|
)
|
||||
Prior service cost amortization
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
Settlements
|
—
|
|
|
—
|
|
|
32
|
|
|
—
|
|
||||
Net periodic benefit cost
|
$
|
2
|
|
|
$
|
(3
|
)
|
|
$
|
41
|
|
|
$
|
(3
|
)
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||
Discount rate
|
3.65
|
%
|
|
2.34
|
%
|
|
3.59
|
%
|
|
2.38
|
%
|
Rate of compensation increase
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||
Discount rate
|
3.60
|
%
|
|
3.06
|
%
|
|
3.65
|
%
|
|
2.79
|
%
|
Expected return on assets:
|
|
|
|
|
|
|
|
||||
Tax exempt accounts
|
3.50
|
%
|
|
7.00
|
%
|
|
7.50
|
%
|
|
7.00
|
%
|
Taxable accounts
|
N/A
|
|
|
4.50
|
%
|
|
N/A
|
|
|
4.50
|
%
|
Rate of compensation increase
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
|
December 31,
|
||||
|
|
2016
|
|
2015
|
||
Health care cost trend rate
|
|
6.73
|
%
|
|
7.16
|
%
|
Rate to which the cost trend is assumed to decline (the ultimate trend rate)
|
|
4.96
|
%
|
|
5.39
|
%
|
Year that the rate reaches the ultimate trend rate
|
|
2021
|
|
|
2018
|
|
|
|
|
Fair Value Measurements at December 31, 2016
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Asset category:
|
|
|
|
|
|
|
|
||||||||
Mutual funds
(1)
|
$
|
12
|
|
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total
|
$
|
12
|
|
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Comprised of approximately
100%
equities as of
December 31, 2016
.
|
|
|
|
Fair Value Measurements at December 31, 2015
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Asset category:
|
|
|
|
|
|
|
|
||||||||
Mutual funds
(1)
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
15
|
|
|
$
|
—
|
|
Total
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
15
|
|
|
$
|
—
|
|
(1)
|
Comprised of approximately
100%
equities as of
December 31, 2015
.
|
|
|
|
Fair Value Measurements at December 31, 2016
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Asset category:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
23
|
|
|
$
|
23
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mutual funds
(1)
|
134
|
|
|
134
|
|
|
—
|
|
|
—
|
|
||||
Fixed income securities
|
91
|
|
|
—
|
|
|
91
|
|
|
—
|
|
||||
Total
|
$
|
248
|
|
|
$
|
157
|
|
|
$
|
91
|
|
|
$
|
—
|
|
(1)
|
Primarily comprised of approximately
31%
equities,
66%
fixed income securities and
3%
cash as of
December 31, 2016
.
|
|
|
|
Fair Value Measurements at December 31, 2015
|
||||||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||
Asset category:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
18
|
|
|
$
|
18
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mutual funds
(1)
|
133
|
|
|
133
|
|
|
—
|
|
|
—
|
|
||||
Fixed income securities
|
102
|
|
|
—
|
|
|
102
|
|
|
—
|
|
||||
Total
|
$
|
253
|
|
|
$
|
151
|
|
|
$
|
102
|
|
|
$
|
—
|
|
(1)
|
Primarily comprised of approximately
56%
equities,
33%
fixed income securities and
11%
cash as of
December 31, 2015
.
|
|
|
Pension Benefits
|
|
|
||||||||
Years
|
|
Funded Plans
|
|
Unfunded Plans
|
|
Other Postretirement Benefits (Gross, Before Medicare Part D)
|
||||||
2017
|
|
$
|
1
|
|
|
$
|
7
|
|
|
$
|
26
|
|
2018
|
|
1
|
|
|
7
|
|
|
25
|
|
|||
2019
|
|
1
|
|
|
6
|
|
|
23
|
|
|||
2020
|
|
1
|
|
|
6
|
|
|
22
|
|
|||
2021
|
|
1
|
|
|
5
|
|
|
19
|
|
|||
2022 – 2026
|
|
6
|
|
|
17
|
|
|
39
|
|
14.
|
RELATED PARTY TRANSACTIONS:
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Affiliated revenues
|
$
|
377
|
|
|
$
|
417
|
|
|
$
|
965
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Accounts receivable from related companies:
|
|
|
|
||||
ETE
|
$
|
22
|
|
|
$
|
110
|
|
Sunoco LP
|
96
|
|
|
3
|
|
||
PES
|
6
|
|
|
10
|
|
||
FGT
|
15
|
|
|
13
|
|
||
Lake Charles LNG
|
4
|
|
|
36
|
|
||
Trans-Pecos Pipeline, LLC
|
1
|
|
|
29
|
|
||
Comanche Trail Pipeline, LLC
|
—
|
|
|
22
|
|
||
Other
|
65
|
|
|
45
|
|
||
Total accounts receivable from related companies
|
$
|
209
|
|
|
$
|
268
|
|
|
|
|
|
||||
Accounts payable to related companies:
|
|
|
|
||||
ETE
|
$
|
—
|
|
|
$
|
1
|
|
Sunoco LP
|
20
|
|
|
5
|
|
||
FGT
|
1
|
|
|
1
|
|
||
Lake Charles LNG
|
3
|
|
|
3
|
|
||
Other
|
19
|
|
|
15
|
|
||
Total accounts payable to related companies
|
$
|
43
|
|
|
$
|
25
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Long-term notes receivable (payable) – related companies:
|
|
|
|
||||
Sunoco LP
|
$
|
87
|
|
|
$
|
(233
|
)
|
Phillips 66
|
(250
|
)
|
|
—
|
|
||
Net long-term notes receivable (payable) – related companies
|
$
|
(163
|
)
|
|
$
|
(233
|
)
|
15.
|
REPORTABLE SEGMENTS:
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Intrastate transportation and storage:
|
|
|
|
|
|
||||||
Revenues from external customers
|
$
|
2,155
|
|
|
$
|
1,912
|
|
|
$
|
2,645
|
|
Intersegment revenues
|
458
|
|
|
338
|
|
|
212
|
|
|||
|
2,613
|
|
|
2,250
|
|
|
2,857
|
|
|||
Interstate transportation and storage:
|
|
|
|
|
|
||||||
Revenues from external customers
|
946
|
|
|
1,008
|
|
|
1,057
|
|
|||
Intersegment revenues
|
23
|
|
|
17
|
|
|
15
|
|
|||
|
969
|
|
|
1,025
|
|
|
1,072
|
|
|||
Midstream:
|
|
|
|
|
|
||||||
Revenues from external customers
|
2,342
|
|
|
2,607
|
|
|
4,770
|
|
|||
Intersegment revenues
|
2,837
|
|
|
2,449
|
|
|
2,053
|
|
|||
|
5,179
|
|
|
5,056
|
|
|
6,823
|
|
|||
Liquids transportation and services:
|
|
|
|
|
|
||||||
Revenues from external customers
|
4,498
|
|
|
3,247
|
|
|
3,730
|
|
|||
Intersegment revenues
|
299
|
|
|
249
|
|
|
181
|
|
|||
|
4,797
|
|
|
3,496
|
|
|
3,911
|
|
|||
Investment in Sunoco Logistics:
|
|
|
|
|
|
||||||
Revenues from external customers
|
9,015
|
|
|
10,302
|
|
|
17,920
|
|
|||
Intersegment revenues
|
136
|
|
|
184
|
|
|
168
|
|
|||
|
9,151
|
|
|
10,486
|
|
|
18,088
|
|
|||
All other:
|
|
|
|
|
|
||||||
Revenues from external customers
|
2,871
|
|
|
15,216
|
|
|
25,353
|
|
|||
Intersegment revenues
|
400
|
|
|
558
|
|
|
465
|
|
|||
|
3,271
|
|
|
15,774
|
|
|
25,818
|
|
|||
Eliminations
|
(4,153
|
)
|
|
(3,795
|
)
|
|
(3,094
|
)
|
|||
Total revenues
|
$
|
21,827
|
|
|
$
|
34,292
|
|
|
$
|
55,475
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Cost of products sold:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
1,897
|
|
|
$
|
1,554
|
|
|
$
|
2,169
|
|
Midstream
|
3,381
|
|
|
3,264
|
|
|
4,893
|
|
|||
Liquids transportation and services
|
3,673
|
|
|
2,597
|
|
|
3,166
|
|
|||
Investment in Sunoco Logistics
|
7,658
|
|
|
9,307
|
|
|
17,135
|
|
|||
All other
|
2,942
|
|
|
14,029
|
|
|
24,129
|
|
|||
Eliminations
|
(4,157
|
)
|
|
(3,722
|
)
|
|
(3,078
|
)
|
|||
Total cost of products sold
|
$
|
15,394
|
|
|
$
|
27,029
|
|
|
$
|
48,414
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Depreciation, depletion and amortization:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
144
|
|
|
$
|
129
|
|
|
$
|
125
|
|
Interstate transportation and storage
|
207
|
|
|
210
|
|
|
203
|
|
|||
Midstream
|
844
|
|
|
720
|
|
|
569
|
|
|||
Liquids transportation and services
|
156
|
|
|
126
|
|
|
113
|
|
|||
Investment in Sunoco Logistics
|
446
|
|
|
382
|
|
|
296
|
|
|||
All other
|
189
|
|
|
362
|
|
|
363
|
|
|||
Total depreciation, depletion and amortization
|
$
|
1,986
|
|
|
$
|
1,929
|
|
|
$
|
1,669
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Equity in earnings (losses) of unconsolidated affiliates:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
35
|
|
|
$
|
32
|
|
|
$
|
27
|
|
Interstate transportation and storage
|
193
|
|
|
197
|
|
|
196
|
|
|||
Midstream
|
19
|
|
|
(19
|
)
|
|
10
|
|
|||
Liquids transportation and services
|
3
|
|
|
(2
|
)
|
|
(3
|
)
|
|||
Investment in Sunoco Logistics
|
34
|
|
|
21
|
|
|
23
|
|
|||
All other
|
(225
|
)
|
|
240
|
|
|
79
|
|
|||
Total equity in earnings of unconsolidated affiliates
|
$
|
59
|
|
|
$
|
469
|
|
|
$
|
332
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
613
|
|
|
$
|
543
|
|
|
$
|
559
|
|
Interstate transportation and storage
|
1,117
|
|
|
1,155
|
|
|
1,212
|
|
|||
Midstream
|
1,133
|
|
|
1,237
|
|
|
1,318
|
|
|||
Liquids transportation and services
|
968
|
|
|
744
|
|
|
591
|
|
|||
Investment in Sunoco Logistics
|
1,233
|
|
|
1,153
|
|
|
971
|
|
|||
All other
|
541
|
|
|
882
|
|
|
1,059
|
|
|||
Total Segment Adjusted EBITDA
|
5,605
|
|
|
5,714
|
|
|
5,710
|
|
|||
Depreciation, depletion and amortization
|
(1,986
|
)
|
|
(1,929
|
)
|
|
(1,669
|
)
|
|||
Interest expense, net
|
(1,317
|
)
|
|
(1,291
|
)
|
|
(1,165
|
)
|
|||
Gains on acquisitions
|
83
|
|
|
—
|
|
|
—
|
|
|||
Gain on sale of AmeriGas common units
|
—
|
|
|
—
|
|
|
177
|
|
|||
Impairment losses
|
(813
|
)
|
|
(339
|
)
|
|
(370
|
)
|
|||
Losses on interest rate derivatives
|
(12
|
)
|
|
(18
|
)
|
|
(157
|
)
|
|||
Non-cash unit-based compensation expense
|
(80
|
)
|
|
(79
|
)
|
|
(68
|
)
|
|||
Unrealized gains (losses) on commodity risk management activities
|
(131
|
)
|
|
(65
|
)
|
|
112
|
|
|||
Inventory valuation adjustments
|
170
|
|
|
(104
|
)
|
|
(473
|
)
|
|||
Losses on extinguishments of debt
|
—
|
|
|
(43
|
)
|
|
(25
|
)
|
|||
Adjusted EBITDA related to discontinued operations
|
—
|
|
|
—
|
|
|
(27
|
)
|
|||
Adjusted EBITDA related to unconsolidated affiliates
|
(946
|
)
|
|
(937
|
)
|
|
(748
|
)
|
|||
Equity in earnings from unconsolidated affiliates
|
59
|
|
|
469
|
|
|
332
|
|
|||
Impairment of investment in an unconsolidated affiliate
|
(308
|
)
|
|
—
|
|
|
—
|
|
|||
Other, net
|
114
|
|
|
20
|
|
|
(36
|
)
|
|||
Income from continuing operations before income tax expense (benefit)
|
$
|
438
|
|
|
$
|
1,398
|
|
|
$
|
1,593
|
|
|
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Assets:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
5,164
|
|
|
$
|
4,882
|
|
|
$
|
4,983
|
|
Interstate transportation and storage
|
10,833
|
|
|
11,345
|
|
|
10,779
|
|
|||
Midstream
|
18,011
|
|
|
17,111
|
|
|
15,562
|
|
|||
Liquids transportation and services
|
11,296
|
|
|
7,235
|
|
|
4,568
|
|
|||
Investment in Sunoco Logistics
|
18,819
|
|
|
15,423
|
|
|
13,619
|
|
|||
All other
|
6,068
|
|
|
9,177
|
|
|
13,007
|
|
|||
Total assets
|
$
|
70,191
|
|
|
$
|
65,173
|
|
|
$
|
62,518
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis):
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
76
|
|
|
$
|
105
|
|
|
$
|
169
|
|
Interstate transportation and storage
|
280
|
|
|
860
|
|
|
411
|
|
|||
Midstream
|
1,255
|
|
|
2,172
|
|
|
1,298
|
|
|||
Liquids transportation and services
|
2,316
|
|
|
2,109
|
|
|
427
|
|
|||
Investment in Sunoco Logistics
|
1,739
|
|
|
2,126
|
|
|
2,510
|
|
|||
All other
|
144
|
|
|
795
|
|
|
679
|
|
|||
Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis)
|
$
|
5,810
|
|
|
$
|
8,167
|
|
|
$
|
5,494
|
|
|
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Advances to and investments in unconsolidated affiliates:
|
|
|
|
|
|
||||||
Intrastate transportation and storage
|
$
|
387
|
|
|
$
|
406
|
|
|
$
|
423
|
|
Interstate transportation and storage
|
2,149
|
|
|
2,516
|
|
|
2,649
|
|
|||
Midstream
|
111
|
|
|
117
|
|
|
138
|
|
|||
Liquids transportation and services
|
29
|
|
|
32
|
|
|
31
|
|
|||
Investment in Sunoco Logistics
|
224
|
|
|
247
|
|
|
226
|
|
|||
All other
|
1,380
|
|
|
1,685
|
|
|
293
|
|
|||
Total advances to and investments in unconsolidated affiliates
|
$
|
4,280
|
|
|
$
|
5,003
|
|
|
$
|
3,760
|
|
16.
|
QUARTERLY FINANCIAL DATA (UNAUDITED):
|
|
|
Quarters Ended
|
|
|
||||||||||||||||
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Total Year
|
||||||||||
2016:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
4,481
|
|
|
$
|
5,289
|
|
|
$
|
5,531
|
|
|
$
|
6,526
|
|
|
$
|
21,827
|
|
Operating income (loss)
|
|
614
|
|
|
715
|
|
|
638
|
|
|
(165
|
)
|
|
1,802
|
|
|||||
Net income (loss)
|
|
376
|
|
|
472
|
|
|
138
|
|
|
(362
|
)
|
|
624
|
|
|||||
Common Unitholders’ interest in net income (loss)
|
|
(67
|
)
|
|
60
|
|
|
(241
|
)
|
|
(762
|
)
|
|
(1,010
|
)
|
|||||
Basic net income (loss) per Common Unit
|
|
$
|
(0.15
|
)
|
|
$
|
0.10
|
|
|
$
|
(0.49
|
)
|
|
$
|
(1.47
|
)
|
|
$
|
(2.06
|
)
|
Diluted net income (loss) per Common Unit
|
|
$
|
(0.15
|
)
|
|
$
|
0.10
|
|
|
$
|
(0.49
|
)
|
|
$
|
(1.47
|
)
|
|
$
|
(2.06
|
)
|
|
|
Quarters Ended
|
|
|
||||||||||||||||
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Total Year
|
||||||||||
2015:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
10,326
|
|
|
$
|
11,540
|
|
|
$
|
6,601
|
|
|
$
|
5,825
|
|
|
$
|
34,292
|
|
Operating income
|
|
608
|
|
|
888
|
|
|
576
|
|
|
187
|
|
|
2,259
|
|
|||||
Net income
|
|
268
|
|
|
839
|
|
|
393
|
|
|
21
|
|
|
1,521
|
|
|||||
Common Unitholders’ interest in net income (loss)
|
|
(48
|
)
|
|
298
|
|
|
59
|
|
|
(327
|
)
|
|
(18
|
)
|
|||||
Basic net income (loss) per Common Unit
|
|
$
|
(0.17
|
)
|
|
$
|
0.67
|
|
|
$
|
0.11
|
|
|
$
|
(0.68
|
)
|
|
$
|
(0.09
|
)
|
Diluted net income (loss) per Common Unit
|
|
$
|
(0.17
|
)
|
|
$
|
0.67
|
|
|
$
|
0.10
|
|
|
$
|
(0.68
|
)
|
|
$
|
(0.10
|
)
|
1.
|
Appendix I – Definition of “Outside Termination Date”
. The definition of “Outside Termination Date” set forth in Appendix I of the Original Agreement is deleted in its entirety and replaced with the following:
|
2.
|
Ratification
. Except as specifically provided in this Amendment, all terms and provisions of the Original Agreement shall remain unchanged and in full force and effect, and the Original Agreement, as modified by this Amendment, is hereby ratified, acknowledged and reaffirmed by the Parties. To the extent any term of this Amendment conflicts with any term of the Original Agreement, the term of this Amendment shall control.
|
3.
|
No Other Amendments
. Except as expressly set forth herein, the execution of this Amendment shall not directly or indirectly in any way whatsoever (a) impair, prejudice or otherwise adversely affect any Party’s right at any time to exercise any right, privilege or remedy in connection with the Original Agreement, (b) amend or alter any provision of the Original Agreement (other than the amendments provided for in this Amendment) or (c) constitute any course of dealing or other basis for altering any obligation of any Party or any right, privilege or remedy of any Party under the Original Agreement.
|
4.
|
References
. Each reference in the Original Agreement to “this Agreement,” “hereunder,” “hereof,” “herein” or any other word or words of similar import shall mean and be a reference to the Original Agreement as amended hereby.
|
5.
|
Counterparts
. This Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile or other electronic transmission shall be deemed an original signature hereto.
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
$
|
1,317
|
|
|
$
|
1,291
|
|
|
$
|
1,165
|
|
|
$
|
1,013
|
|
|
$
|
788
|
|
Capitalized interest
|
200
|
|
|
163
|
|
|
101
|
|
|
45
|
|
|
101
|
|
|||||
Interest charges included in rental expense
|
9
|
|
|
19
|
|
|
17
|
|
|
16
|
|
|
6
|
|
|||||
Distribution to the Series A Convertible Redeemable Preferred Units
|
—
|
|
|
3
|
|
|
3
|
|
|
6
|
|
|
8
|
|
|||||
Accretion of the Series A Convertible Redeemable Preferred Units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Total fixed charges
|
1,526
|
|
|
1,476
|
|
|
1,286
|
|
|
1,080
|
|
|
904
|
|
|||||
Earnings:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from continuing operations before income tax expense and noncontrolling interest
|
438
|
|
|
1,398
|
|
|
1,593
|
|
|
810
|
|
|
1,817
|
|
|||||
Less: equity in earnings of unconsolidated affiliates
|
59
|
|
|
469
|
|
|
332
|
|
|
236
|
|
|
212
|
|
|||||
Total earnings
|
379
|
|
|
929
|
|
|
1,261
|
|
|
574
|
|
|
1,605
|
|
|||||
Add:
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
1,526
|
|
|
1,476
|
|
|
1,286
|
|
|
1,080
|
|
|
904
|
|
|||||
Amortization of capitalized interest
|
18
|
|
|
11
|
|
|
8
|
|
|
6
|
|
|
5
|
|
|||||
Distributed income of equity investees
|
406
|
|
|
440
|
|
|
291
|
|
|
313
|
|
|
208
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest capitalized
|
(200
|
)
|
|
(163
|
)
|
|
(101
|
)
|
|
(45
|
)
|
|
(101
|
)
|
|||||
Income available for fixed charges
|
$
|
2,129
|
|
|
$
|
2,693
|
|
|
$
|
2,745
|
|
|
$
|
1,928
|
|
|
$
|
2,621
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
1.40
|
|
|
1.82
|
|
|
2.13
|
|
|
1.79
|
|
|
2.90
|
|
Aqua-PVR Water Services, LLC, a Delaware limited liability company
|
Arguelles Pipeline SRL, a Mexico SRL
|
Atlantic Petroleum (Out) LLC, a Delaware limited liability company
|
Atlantic Petroleum Corporation, a Delaware corporation
|
Atlantic Petroleum Delaware Corporation , a Delaware corporation
|
Atlantic Pipeline (Out) L.P. Texas limited partnership
|
Atlantic Refining & Marketing LLC, a Delaware limited liability company
|
Bakken Gathering LLC, a Delaware limited liability company
|
Bakken Holdings Company LLC, a Delaware limited liability company
|
Bakken Pipeline Investments LLC, a Delaware limited liability company
|
Bayou Bridge Pipeline, LLC, a Delaware limited liability company
|
BBP Construction Management, LLC, a Delaware limited liability company
|
CDM Environmental & Technical Services LLC, a Delaware limited liability company
|
CDM Holdings LLC, a Delaware limited liability company
|
CDM Resource Management LLC, a Delaware limited liability company
|
Chalkley Gathering Company, LLC, a Texas limited liability company
|
Change Up Acquisition Corporation, a Delaware corporation
|
Citrus Energy Services, Inc., a Delaware corporation
|
Citrus ETP Finance LLC, a Delaware limited liability company
|
Citrus, LLC, a Delaware limited liability company
|
Clean Air Action Corporation, a Delaware corporation
|
CMA Pipeline Partnership, LLC, a Texas limited liability company
|
Comanche Trail Pipeline, LLC, a Texas limited liability company
|
Connect Gas Pipeline LLC, a Delaware limited liability company
|
CrossCountry Citrus, LLC, a Delaware limited liability company
|
CrossCountry Energy, LLC, a Delaware limited liability company
|
Dakota Access Holdings, LLC, a Delaware limited liability company
|
Dakota Access Truck Terminals, LLC, a Delaware limited liability company
|
Dakota Access, LLC, a Delaware limited liability company
|
DAPL-ETCO Construction Management, LLC, a Delaware limited liability company
|
DAPL-ETCO Operations Management, LLC, a Delaware limited liability company
|
Dulcet Acquisition LLC, a Delaware limited liability company
|
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 Canada, 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 Company, a Delaware corporation
|
Energy Transfer Fuel GP, LLC, a Delaware limited liability company
|
Energy Transfer Fuel, LP, a Delaware limited partnership
|
Energy Transfer Group, LLC, 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 Technologies, Ltd., a Texas limited partnership
|
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 Canada, ULC, a BC, Canada unlimited liability company
|
ET Rover Pipeline LLC, a Delaware limited liability company
|
ETC Bayou Bridge 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 Field Services LLC, a Delaware limited liability company
|
ETC Gas Company, Ltd., a Texas limited partnership
|
ETC Gathering, LLC, a Texas limited liability company
|
ETC Hydrocarbons, LLC, a Texas limited liability company
|
ETC Illinois LLC, a Delaware limited liability company
|
ETC Interstate Procurement Company, LLC, a Delaware limited liability company
|
ETC Intrastate Procurement Company, LLC, a Delaware limited liability company
|
ETC Katy Pipeline, Ltd., a Texas limited partnership
|
ETC M-A Acquisition LLC, a Delaware limited liability company
|
ETC Marketing, Ltd., a Texas limited partnership
|
ETC Midcontinent Express Pipeline, L.L.C., a Delaware limited liability company
|
ETC New Mexico Pipeline, L.P., a New Mexico limited partnership
|
ETC NGL Marketing, LLC, a Texas limited liability company
|
ETC NGL Transport, LLC, a Texas limited liability company
|
ETC North Dakota Terminalling, LLC, a Delaware limited liability company
|
ETC Northeast Development, LLC, a West Virigina limited liability company
|
ETC Northeast Pipeline, LLC, a Delaware limited liability company
|
ETC Oasis GP, LLC a Texas limited liability company
|
ETC Oasis, L.P., a Delaware limited partnership
|
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
|
Fayetteville Express Pipeline, LLC, a Delaware limited liability company
|
FEP Arkansas Pipeline, LLC, an Arkansas limited liability company
|
Fieldcrest Resources LLC, a Delaware limited liability company
|
Five Dawaco, LLC, a Texas limited liability company
|
Florida Gas Transmission Company, LLC, a Delaware limited liability company
|
FrontStreet Hugoton LLC, a Delaware limited liability company
|
Galveston Bay Gathering, LLC, a Texas limited liability company
|
Gulf States Transmission LLC, a Louisiana limited liability company
|
Helios Assurance Company, a Limited Bermuda other
|
Heritage ETC GP, L.L.C., a Delaware limited liability company
|
Heritage ETC, L.P., a Delaware limited partnership
|
Heritage Holdings, Inc., a Delaware corporation
|
Houston Pipe Line Company LP, a Delaware limited partnership
|
HP Houston Holdings, L.P., a Delaware limited partnership
|
HPL Asset Holdings LP, a Delaware limited partnership
|
HPL Consolidation LP, a Delaware limited partnership
|
HPL GP, LLC, a Delaware limited liability company
|
HPL Holdings GP, L.L.C., a Delaware limited liability company
|
HPL Houston Pipe Line Company, LLC, a Delaware limited liability company
|
HPL Leaseco LP, a Delaware limited partnership
|
HPL Resources Company LP, a Delaware limited partnership
|
HPL Storage GP LLC, a Delaware limited liability company
|
Jalisco Corporation, a California corporation
|
Japan Sun Oil Company, Ltd., a Japan other
|
K Rail LLC, a Delaware limited liability company
|
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 Export Company, LLC, a Delaware limited liability company
|
Lavan Petroleum Company (LAPCO), an Iran, Islamic Republic of other
|
Lee 8 Storage Partnership, a Delaware limited partnership
|
Lesley Corporation, a Delaware corporation
|
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 other
|
LJL, LLC, a West Virginia limited liability company
|
Loadout LLC, a Delaware limited liability company
|
Lobo Pipeline Company LLC, a Delaware limited liability company
|
Lone Star NGL Asset GP LLC, a Delaware limited liability company
|
Lone Star NGL Asset Holdings II LLC, a Delaware limited liability company
|
Lone Star NGL Asset Holdings LLC, a Delaware limited liability company
|
Lone Star NGL Development LP, a Delaware limited partnership
|
Lone Star NGL Fractionators LLC, a Delaware limited liability company
|
Lone Star NGL Hastings 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 Pipeline LP, a Delaware limited partnership
|
Lone Star NGL Product Services LLC, a Delaware limited liability company
|
Lone Star NGL Refinery Services LLC, a Delaware limited liability company
|
Lone Star NGL Sea Robin LLC, a Delaware limited liability company
|
Lugrasa, S.A., a Panama corporation
|
Mascot, Inc. (MA), a Massachusetts corporation
|
Materials Handling Solutions LLC, a Delaware limited liability company
|
Mi Vida JV LLC, a Delaware limited liability company
|
Mid-Continent Pipe Line (Out) LLC, a Texas limited liability company
|
Midcontinent Express Pipeline LLC, a Delaware limited liability company
|
Midstream Gas Services, LLC, a Texas limited liability company
|
NSL Energy Marketing Joint Venture, a limited partnership
|
Oasis Partner Company, a Delaware corporation
|
Oasis Pipe Line Company, a Delaware corporation
|
Oasis Pipe Line Company Texas L.P., a Texas limited partnership
|
Oasis Pipe Line Finance Company, a Delaware corporation
|
Oasis Pipe Line Management 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 other
|
Oil Insurance Limited, Bermuda limited 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
|
Panther Acquisition Company, LLC, a Delaware limited liability company
|
PEI Power Corporation, a Pennsylvania corporation
|
PEI Power II, LLC, a Pennsylvania corporation
|
Pelico Pipeline, LLC, a Delaware limited liability company
|
Penn Virginia Operating Co., LLC, a Delaware limited liability company
|
PennTex Finance Corp., a Delaware limited liability company
|
PennTex Midstream GP, LLC, a Delaware limited liability company
|
PennTex Midstream Management Company, LLC, a Delaware limited liability company
|
PennTex Midstream Operating, LLC, a Delaware limited liability company
|
PennTex Midstream Partners, LP, a Delaware limited partnership
|
PennTex Midstream Partners, LLC, a Delaware limited liability company
|
PennTex NLA Holdings, LLC, a Delaware limited liability company
|
PennTex North Louisiana, LLC, a Delaware limited liability company
|
PennTex North Louisiana Operating 3, LLC, a Delaware limited liability company
|
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
|
Puerto Rico Sun Oil Company LLC, a Delaware limited liability company
|
PVR Midstream JV Holdings LLC, a Delaware limited liability company
|
Ranch Westex JV LLC, a Delaware limited liability company
|
Regency Crude Marketing LLC, a Delaware limited liability company
|
Regency DeSoto Pipeline LLC, a Texas limited liability company
|
Regency DeSoto-Hesco Services LLC, a Texas limited liability company
|
Regency Employees Management Holdings LLC, a Delaware limited liability company
|
Regency Employees Management LLC, a Delaware limited liability company
|
Regency Energy Finance Corp., a Delaware corporation
|
Regency Energy Partners LP, a Delaware limited partnership
|
Regency ERCP LLC, a Delaware limited liability company
|
Regency Gas Services LP, a Delaware limited partnership
|
Regency GOM LLC, a Texas limited liability company
|
Regency GP LLC, a Delaware limited liability company
|
Regency GP LP, a Delaware limited partnership
|
Regency Haynesville Intrastate Gas LLC, a Delaware limited liability company
|
Regency Hydrocarbons LLC, an Oklahoma limited liability company
|
Regency Intrastate Gas LP, a Delaware limited partnership
|
Regency Laverne LLC, an Oklahoma limited liability company
|
Regency Liquids Pipeline LLC, a Delaware limited liability company
|
Regency Marcellus Gas Gathering LLC, a Delaware limited liability company
|
Regency Mi Vida LLC, a Delaware limited liability company
|
Regency NEPA Gas Gathering LLC, a Texas limited liability company
|
Regency OLP GP LLC, a Delaware limited liability company
|
Regency Pipeline LLC, a Delaware limited liability company
|
Regency Quitman Gathering LLC, a Delaware limited liability company
|
Regency Ranch JV LLC, a Delaware limited liability company
|
Regency Texas Pipeline LLC, a Delaware limited liability company
|
Regency Utica Gas Gathering LLC, a Delaware limited liability company
|
Regency Utica Holdco LLC, a Delaware limited liability company
|
Regency Vaughn Gathering LLC, a Texas limited liability company
|
RGP Marketing LLC, a Texas limited liability company
|
RGP Westex Gathering Inc., a Texas corporation
|
RGU West LLC, a Texas limited liability company
|
RIGS GP LLC, a Delaware limited liability company
|
RIGS Haynesville Partnership Co., a Delaware partnership
|
Rover Pipeline LLC, a Delaware limited liability company
|
RSS Water Services LLC, a Delaware limited liability company
|
Sea Robin Pipeline Company, LLC , a Delaware limited liability company
|
SEC Energy Products & Services, L.P., a Texas limited partnership
|
SEC Energy Realty GP, LLC, a Texas limited liability company
|
SEC General Holdings, LLC, a Texas limited liability company
|
SEC-EP Realty Ltd., a Texas limited partnership
|
Southern Union Gas Company, Inc., a Texas corporation
|
Southern Union Panhandle LLC, a Delaware limited liability company
|
SU Gas Services Operating Company, Inc., a Delaware corporation
|
SU Holding Company, Inc., a Delaware corporation
|
SUG Holding Company, LLC, a Delaware limited liability company
|
SUGAir Aviation Company, a Delaware corporation
|
Sun Alternate Energy Corporation, a Delaware corporation
|
Sun Atlantic Refining and Marketing B.V., a Netherlands other
|
Sun Atlantic Refining and Marketing B.V., LLC, a Delaware limited liability company
|
Sun Atlantic Refining and Marketing Company, a Delaware limited liability company
|
Sun Canada, Inc., a Delaware corporation
|
Sun Company, Inc., a Delaware corporation
|
Sun Company, Inc., a Pennsylvania corporation
|
Sun International Limited, a Bermuda other
|
Sun Lubricants and Specialty Products Inc., a Quebec corporation
|
Sun Mexico One, Inc., a Delaware corporation
|
Sun Mexico Two, Inc., a Delaware corporation
|
Sun Oil Company, a Delaware corporation
|
Sun Oil Export Company, a Delaware corporation
|
Sun Oil International, Inc., a Delaware corporation
|
Sun Petrochemicals, Inc., a Delaware corporation
|
Sun Pipe Line Company, LLC, a Texas limited liability company
|
Sun Pipe Line Delaware (Out) LLC, a Delaware limited liability company
|
Sun Refining and Marketing Company, a Delaware corporation
|
Sun Services Corporation, a Pennsylvania corporation
|
Sun Transport, LLC, a Pennsylvania limited liability company
|
Sun-Del Pipeline LLC, a Delaware limited liability company
|
Sun-Del Services, Inc., a Delaware corporation
|
Suncrest Resources LLC, a Delaware limited liability company
|
Sunoco de Mexico, S.A. de C.V., a Mexico other
|
Sunoco Overseas, Inc., a Delaware corporation
|
Sunoco Partners Lease Acquisition & Marketing LLC, a Delaware limited partnership
|
Sunoco Partners LLC, a Pennsylvania limited liability company
|
Sunoco Power Marketing L.L.C., a Pennsylvania limited liability company
|
Sunoco Receivables Corporation, Inc., a Delaware corporation
|
Sunoco, Inc., a Pennsylvania corporation
|
Sunoco, Inc. (R&M), LLC, a Pennsylvania limited liability company
|
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 New Claymont Investment Company, a Delaware corporation
|
The Sunoco Foundation, a Pennsylvania non profit corporation
|
Toney Fork LLC, a Delaware limited liability company
|
Trans-Pecos Pipeline, LLC, a Texas limited liability company
|
Transwestern Pipeline Company, LLC, a Delaware limited liability company
|
Trunkline Field Services LLC, a Delaware limited liability company
|
Trunkline Gas Company, LLC, a Delaware limited liability company
|
Trunkline LNG Holdings LLC, a Delaware limited liability company
|
Venezoil, C.A., a Venezuela other
|
Vista Mar Pipeline, LLC, a Texas limited liability company
|
West Texas Gathering Company, a Delaware corporation
|
Westex Energy LLC, a Delaware limited liability company
|
WGP-KHC, LLC, a Delaware limited liability company
|
Whiskey Bay Gathering Company, LLC, a Delaware limited liability company
|
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
|
Dakota Access Holdings LLC, a Delaware limited liability company
|
Dakota Access, LLC, a Delaware limited liability company
|
Dakota Access Truck Terminals, LLC, a Delaware limited liability company
|
Eastern Gulf Crude Access, LLC, a Delaware limited liability company
|
Energy Transfer Crude Oil Company, LLC, a Delaware limited liability company
|
ETCO Holdings LLC, a Delaware limited liability company
|
Excel Pipeline LLC, a Delaware limited liability company
|
Explorer Pipeline Company, a Delaware corporation
|
Inland Corporation, an Ohio corporation
|
Mid-Valley Pipeline Company, an Ohio corporation
|
Permian Express Partners LLC, a Delaware limited liability company
|
Permian Express Terminal LLC, a Delaware limited liability company
|
Price River Terminal, LLC, a Texas limited liability company
|
Sun Pipe Line Company of Delaware 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 Midland Gathering LLC, a Texas limited liability company
|
Sunoco Midland Terminal LLC, a Texas limited liability company
|
Sunoco Partners Marketing & Terminals L.P., a Texas limited partnership
|
Sunoco Partners NGL Facilities LLC, a Delaware limited liability company
|
Sunoco Partners Operating LLC, a Delaware limited liability company
|
Sunoco Partners Real Estate Acquisition LLC, a Delaware limited liability company
|
Sunoco Partners Rockies LLC, a Delaware limited liability company
|
Sunoco Pipeline Acquisition LLC, a Delaware limited liability company
|
Sunoco Pipeline L.P., a Texas limited partnership
|
SXL Acquisition Sub LLC, a Delaware limited liability company
|
SXL Acquisition Sub LP, a Delaware limited partnership
|
West Shore Pipe Line Company, a Delaware corporation
|
West Texas Gulf Pipe Line Company, a Delaware corporation
|
Wolverine Pipe Line Company, a Delaware corporation
|
Yellowstone Pipe Line Company, a Delaware corporation
|
1.
|
I have reviewed this annual report on Form 10-K of Energy Transfer Partners, 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 Partners, 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
|
|