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ý
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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73-1493906
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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Large accelerated filer
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ý
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Accelerated filer
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¨
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Non-accelerated filer
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¨
(Do not check if a smaller reporting company)
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Smaller reporting company
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¨
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Emerging growth company
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¨
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/d
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per day
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AOCI
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accumulated other comprehensive income (loss)
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BBtu
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billion British thermal units
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Btu
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British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used
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Capacity
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capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
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CDM
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CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively
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Citrus
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Citrus, LLC
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DOJ
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United States Department of Justice
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EPA
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United States Environmental Protection Agency
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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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ETE
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Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC for the periods presented herein
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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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HPC
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RIGS Haynesville Partnership Co.
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IDRs
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incentive distribution rights
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Legacy ETP Preferred Units
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legacy ETP Series A cumulative convertible preferred units
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LIBOR
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London Interbank Offered Rate
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MBbls
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thousand barrels
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MEP
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Midcontinent Express Pipeline LLC
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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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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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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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Regency
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Regency Energy Partners LP
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Retail Holdings
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ETP Retail Holdings, LLC, a wholly-owned subsidiary of Sunoco, Inc.
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RIGS
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Regency Intrastate Gas LP
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Rover
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Rover Pipeline LLC, a subsidiary of ETP
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SEC
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Securities and Exchange Commission
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Series A Preferred Units
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6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Series B Preferred Units
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6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Series C Preferred Units
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7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Series D Preferred Units
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7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Sunoco Logistics
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Sunoco Logistics Partners L.P.
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Transwestern
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Transwestern Pipeline Company, LLC
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Trunkline
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Trunkline Gas Company, LLC, a subsidiary of Panhandle
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USAC
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USA Compression Partners, LP
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June 30, 2018
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December 31, 2017
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||||
ASSETS
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||||
Current assets:
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||||
Cash and cash equivalents
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$
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494
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$
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306
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Accounts receivable, net
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3,684
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3,946
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Accounts receivable from related companies
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334
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318
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Inventories
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1,256
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1,589
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Income taxes receivable
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172
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135
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Derivative assets
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57
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24
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Other current assets
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550
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210
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Total current assets
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6,547
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6,528
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||||
Property, plant and equipment
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69,637
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67,699
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Accumulated depreciation and depletion
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(9,861
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)
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(9,262
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)
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59,776
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58,437
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||||
Advances to and investments in unconsolidated affiliates
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3,636
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3,816
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Other non-current assets, net
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762
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758
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Intangible assets, net
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4,988
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5,311
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Goodwill
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2,861
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3,115
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Total assets
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$
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78,570
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$
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77,965
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June 30, 2018
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December 31, 2017
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||||
LIABILITIES AND EQUITY
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Current liabilities:
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||||
Accounts payable
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$
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3,488
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$
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4,126
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Accounts payable to related companies
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329
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209
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Derivative liabilities
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385
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109
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Accrued and other current liabilities
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2,284
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2,143
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Current maturities of long-term debt
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155
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407
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Total current liabilities
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6,641
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6,994
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Long-term debt, less current maturities
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33,741
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32,687
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Non-current derivative liabilities
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135
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145
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|
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Deferred income taxes
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2,917
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2,883
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Other non-current liabilities
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1,079
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1,084
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||
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||||
Commitments and contingencies
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|
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||||
Redeemable noncontrolling interests
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21
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21
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||||
Equity:
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|
||||
Limited Partners:
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||||
Series A Preferred Unitholders
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958
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944
|
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||
Series B Preferred Unitholders
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556
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547
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Series C Preferred Unitholders
|
442
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|
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—
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|
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Common Unitholders
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25,546
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26,531
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General Partner
|
359
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244
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|
||
Accumulated other comprehensive income
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4
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3
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||
Total partners’ capital
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27,865
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28,269
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Noncontrolling interest
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6,171
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5,882
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|
||
Total equity
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34,036
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34,151
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|
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Total liabilities and equity
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$
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78,570
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$
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77,965
|
|
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Three Months Ended
June 30, |
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Six Months Ended
June 30, |
||||||||||||
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2018
|
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2017*
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2018
|
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2017*
|
||||||||
REVENUES:
|
|
|
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|
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||||||||
Natural gas sales
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$
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1,024
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$
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1,022
|
|
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$
|
2,086
|
|
|
$
|
2,034
|
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NGL sales
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2,141
|
|
|
1,485
|
|
|
4,171
|
|
|
3,032
|
|
||||
Crude sales
|
4,241
|
|
|
2,345
|
|
|
7,495
|
|
|
4,887
|
|
||||
Gathering, transportation and other fees
|
1,464
|
|
|
1,067
|
|
|
2,861
|
|
|
2,091
|
|
||||
Refined product sales
|
413
|
|
|
304
|
|
|
852
|
|
|
775
|
|
||||
Other
|
127
|
|
|
353
|
|
|
225
|
|
|
652
|
|
||||
Total revenues
|
9,410
|
|
|
6,576
|
|
|
17,690
|
|
|
13,471
|
|
||||
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
||||||||
Cost of products sold
|
7,140
|
|
|
4,624
|
|
|
13,128
|
|
|
9,674
|
|
||||
Operating expenses
|
627
|
|
|
539
|
|
|
1,231
|
|
|
1,031
|
|
||||
Depreciation, depletion and amortization
|
588
|
|
|
557
|
|
|
1,191
|
|
|
1,117
|
|
||||
Selling, general and administrative
|
112
|
|
|
120
|
|
|
224
|
|
|
230
|
|
||||
Total costs and expenses
|
8,467
|
|
|
5,840
|
|
|
15,774
|
|
|
12,052
|
|
||||
OPERATING INCOME
|
943
|
|
|
736
|
|
|
1,916
|
|
|
1,419
|
|
||||
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
||||||||
Interest expense, net
|
(358
|
)
|
|
(336
|
)
|
|
(704
|
)
|
|
(668
|
)
|
||||
Equity in earnings (losses) of unconsolidated affiliates
|
106
|
|
|
(61
|
)
|
|
34
|
|
|
12
|
|
||||
Gain on Sunoco LP common unit repurchase
|
—
|
|
|
—
|
|
|
172
|
|
|
—
|
|
||||
Loss on deconsolidation of CDM
|
(86
|
)
|
|
—
|
|
|
(86
|
)
|
|
—
|
|
||||
Gains (losses) on interest rate derivatives
|
20
|
|
|
(25
|
)
|
|
72
|
|
|
(20
|
)
|
||||
Other, net
|
46
|
|
|
61
|
|
|
106
|
|
|
80
|
|
||||
INCOME BEFORE INCOME TAX EXPENSE
|
671
|
|
|
375
|
|
|
1,510
|
|
|
823
|
|
||||
Income tax expense
|
69
|
|
|
79
|
|
|
29
|
|
|
134
|
|
||||
NET INCOME
|
602
|
|
|
296
|
|
|
1,481
|
|
|
689
|
|
||||
Less: Net income attributable to noncontrolling interest
|
170
|
|
|
94
|
|
|
334
|
|
|
156
|
|
||||
NET INCOME ATTRIBUTABLE TO PARTNERS
|
432
|
|
|
202
|
|
|
1,147
|
|
|
533
|
|
||||
Series A Preferred Unitholders’ interest in net income
|
15
|
|
|
—
|
|
|
30
|
|
|
—
|
|
||||
Series B Preferred Unitholders’ interest in net income
|
9
|
|
|
—
|
|
|
18
|
|
|
—
|
|
||||
Series C Preferred Unitholders’ interest in net income
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
||||
General Partner’s interest in net income
|
402
|
|
|
251
|
|
|
804
|
|
|
457
|
|
||||
Class H Unitholder’s interest in net income
|
—
|
|
|
—
|
|
|
—
|
|
|
93
|
|
||||
Common Unitholders’ interest in net income (loss)
|
$
|
—
|
|
|
$
|
(49
|
)
|
|
$
|
289
|
|
|
$
|
(17
|
)
|
NET INCOME (LOSS) PER COMMON UNIT:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.01
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
0.23
|
|
|
$
|
(0.02
|
)
|
Diluted
|
$
|
(0.01
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
0.23
|
|
|
$
|
(0.02
|
)
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
||||||||
Net income
|
$
|
602
|
|
|
$
|
296
|
|
|
$
|
1,481
|
|
|
689
|
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
|
||||||||
Change in value of available-for-sale securities
|
—
|
|
|
1
|
|
|
(2
|
)
|
|
3
|
|
||||
Actuarial loss relating to pension and other postretirement benefit plans
|
—
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(3
|
)
|
||||
Change in other comprehensive income from unconsolidated affiliates
|
2
|
|
|
(1
|
)
|
|
7
|
|
|
(1
|
)
|
||||
|
2
|
|
|
(1
|
)
|
|
3
|
|
|
(1
|
)
|
||||
Comprehensive income
|
604
|
|
|
295
|
|
|
1,484
|
|
|
688
|
|
||||
Less: Comprehensive income attributable to noncontrolling interest
|
170
|
|
|
94
|
|
|
334
|
|
|
156
|
|
||||
Comprehensive income attributable to partners
|
$
|
434
|
|
|
$
|
201
|
|
|
$
|
1,150
|
|
|
$
|
532
|
|
|
Limited Partners
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||
|
Series A Preferred Units
|
|
Series B Preferred Units
|
|
Series C Preferred Units
|
|
Common Units
|
|
General Partner
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Noncontrolling Interest
|
|
Total
|
||||||||||||||||
Balance, December 31, 2017
|
$
|
944
|
|
|
$
|
547
|
|
|
$
|
—
|
|
|
$
|
26,531
|
|
|
$
|
244
|
|
|
$
|
3
|
|
|
$
|
5,882
|
|
|
$
|
34,151
|
|
Distributions to partners
|
(15
|
)
|
|
(9
|
)
|
|
—
|
|
|
(1,315
|
)
|
|
(672
|
)
|
|
—
|
|
|
—
|
|
|
(2,011
|
)
|
||||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(359
|
)
|
|
(359
|
)
|
||||||||
Units issued for cash
|
—
|
|
|
—
|
|
|
436
|
|
|
39
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
475
|
|
||||||||
Capital contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
318
|
|
|
318
|
|
||||||||
Repurchases of common units
|
—
|
|
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(24
|
)
|
||||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
||||||||
Other, net
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
26
|
|
|
(17
|
)
|
|
(2
|
)
|
|
(4
|
)
|
|
2
|
|
||||||||
Net income
|
30
|
|
|
18
|
|
|
6
|
|
|
289
|
|
|
804
|
|
|
—
|
|
|
334
|
|
|
1,481
|
|
||||||||
Balance, June 30, 2018
|
$
|
958
|
|
|
$
|
556
|
|
|
$
|
442
|
|
|
$
|
25,546
|
|
|
$
|
359
|
|
|
$
|
4
|
|
|
$
|
6,171
|
|
|
$
|
34,036
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017*
|
||||
OPERATING ACTIVITIES
|
|
|
|
||||
Net income
|
$
|
1,481
|
|
|
$
|
689
|
|
Reconciliation of net income to net cash provided by operating activities:
|
|
|
|
||||
Depreciation, depletion and amortization
|
1,191
|
|
|
1,117
|
|
||
Deferred income taxes
|
52
|
|
|
121
|
|
||
Non-cash compensation expense
|
41
|
|
|
38
|
|
||
Gain on Sunoco LP common unit repurchase
|
(172
|
)
|
|
—
|
|
||
Loss on deconsolidation of CDM
|
86
|
|
|
—
|
|
||
Distributions on unvested awards
|
(17
|
)
|
|
(15
|
)
|
||
Equity in earnings of unconsolidated affiliates
|
(34
|
)
|
|
(12
|
)
|
||
Distributions from unconsolidated affiliates
|
215
|
|
|
197
|
|
||
Other non-cash
|
(122
|
)
|
|
(98
|
)
|
||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations
|
229
|
|
|
(387
|
)
|
||
Net cash provided by operating activities
|
2,950
|
|
|
1,650
|
|
||
INVESTING ACTIVITIES
|
|
|
|
||||
Cash proceeds from CDM contribution
|
1,227
|
|
|
—
|
|
||
Cash proceeds from Sunoco LP common unit repurchase
|
540
|
|
|
—
|
|
||
Cash proceeds from Bakken pipeline transaction
|
—
|
|
|
2,000
|
|
||
Cash paid for acquisition of PennTex noncontrolling interest
|
—
|
|
|
(280
|
)
|
||
Cash paid for all other acquisitions
|
(29
|
)
|
|
(261
|
)
|
||
Capital expenditures, excluding allowance for equity funds used during construction
|
(3,409
|
)
|
|
(2,842
|
)
|
||
Contributions in aid of construction costs
|
60
|
|
|
10
|
|
||
Contributions to unconsolidated affiliates
|
(13
|
)
|
|
(225
|
)
|
||
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
31
|
|
|
94
|
|
||
Proceeds from the sale of assets
|
2
|
|
|
25
|
|
||
Other
|
—
|
|
|
(7
|
)
|
||
Net cash used in investing activities
|
(1,591
|
)
|
|
(1,486
|
)
|
||
FINANCING ACTIVITIES
|
|
|
|
||||
Proceeds from borrowings
|
12,476
|
|
|
11,466
|
|
||
Repayments of debt
|
(12,018
|
)
|
|
(10,953
|
)
|
||
Cash paid to affiliate notes
|
—
|
|
|
(255
|
)
|
||
Common units issued for cash
|
39
|
|
|
990
|
|
||
Preferred units issued for cash
|
436
|
|
|
—
|
|
||
Capital contributions from noncontrolling interest
|
318
|
|
|
456
|
|
||
Distributions to partners
|
(2,011
|
)
|
|
(1,702
|
)
|
||
Distributions to noncontrolling interest
|
(359
|
)
|
|
(186
|
)
|
||
Repurchases of common units
|
(24
|
)
|
|
—
|
|
||
Redemption of Legacy ETP Preferred Units
|
—
|
|
|
(53
|
)
|
||
Debt issuance costs
|
(38
|
)
|
|
(20
|
)
|
||
Other
|
10
|
|
|
5
|
|
||
Net cash used in financing activities
|
(1,171
|
)
|
|
(252
|
)
|
||
Increase (decrease) in cash and cash equivalents
|
188
|
|
|
(88
|
)
|
||
Cash and cash equivalents, beginning of period
|
306
|
|
|
360
|
|
||
Cash and cash equivalents, end of period
|
$
|
494
|
|
|
$
|
272
|
|
1.
|
ORGANIZATION AND BASIS OF PRESENTATION
|
•
|
ETC OLP, Regency and PennTex, which are primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP and Regency own and operate, through their wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, West Virginia, Colorado and Ohio.
|
•
|
Energy Transfer Interstate Holdings, LLC, (“ETIH”) with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which is the parent company of:
|
•
|
Transwestern, engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
|
•
|
ETC Fayetteville Express Pipeline, LLC, which directly owns a
50%
interest in FEP, which owns
100%
of the Fayetteville Express interstate natural gas pipeline.
|
•
|
ETC Tiger Pipeline, LLC, engaged in interstate transportation of natural gas.
|
•
|
CrossCountry Energy, LLC, which indirectly owns a
50%
interest in Citrus, which owns
100%
of the FGT interstate natural gas pipeline.
|
•
|
ETC Midcontinent Express Pipeline, L.L.C., which directly owns a
50%
interest in MEP.
|
•
|
ET Rover Pipeline, LLC, which ETIH directly owns a
50.1%
interest in, which owns a
65%
interest in the Rover pipeline.
|
•
|
ETC Compression, LLC, engaged in natural gas compression services and related equipment sales. As discussed further in
Note 2
below, in April 2018, we contributed certain assets to USAC.
|
•
|
ETP Holdco, which indirectly owns Panhandle and Sunoco, Inc. Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. Sunoco Inc.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. ETP Holdco also holds an equity method investment in ETP through its ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in ETP’s consolidated financial statements.
|
•
|
Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
|
|
Three Months Ended June 30, 2017
|
|
Six Months Ended June 30, 2017
|
||||||||||||||||||||
|
As Originally Reported
|
|
Effect of Change
|
|
As Adjusted
|
|
As Originally Reported
|
|
Effect of Change
|
|
As Adjusted
|
||||||||||||
Cost of products sold
(1)
|
$
|
4,628
|
|
|
$
|
(4
|
)
|
|
$
|
4,624
|
|
|
$
|
9,707
|
|
|
$
|
(33
|
)
|
|
$
|
9,674
|
|
Operating income
|
732
|
|
|
4
|
|
|
736
|
|
|
1,386
|
|
|
33
|
|
|
1,419
|
|
||||||
Income before income tax expense
|
371
|
|
|
4
|
|
|
375
|
|
|
790
|
|
|
33
|
|
|
823
|
|
||||||
Net income
|
292
|
|
|
4
|
|
|
296
|
|
|
656
|
|
|
33
|
|
|
689
|
|
||||||
Net income attributable to partners
|
199
|
|
|
3
|
|
|
202
|
|
|
523
|
|
|
10
|
|
|
533
|
|
||||||
Net loss per common unit – basic
|
(0.04
|
)
|
|
—
|
|
|
(0.04
|
)
|
|
(0.04
|
)
|
|
0.02
|
|
|
(0.02
|
)
|
||||||
Net loss per common unit – diluted
|
(0.04
|
)
|
|
—
|
|
|
(0.04
|
)
|
|
(0.04
|
)
|
|
0.02
|
|
|
(0.02
|
)
|
||||||
Comprehensive income
|
291
|
|
|
4
|
|
|
295
|
|
|
655
|
|
|
33
|
|
|
688
|
|
||||||
Comprehensive income attributable to partners
|
198
|
|
|
3
|
|
|
201
|
|
|
522
|
|
|
10
|
|
|
532
|
|
|
Six Months Ended June 30, 2017
|
||||||||||
|
As Originally Reported
|
|
Effect of Change
|
|
As Adjusted
|
||||||
Net income
|
$
|
656
|
|
|
$
|
33
|
|
|
$
|
689
|
|
Inventory valuation adjustments
|
56
|
|
|
(56
|
)
|
|
—
|
|
|||
Net change in operating assets and liabilities, net of effects from acquisitions (change in inventories)
|
(410
|
)
|
|
23
|
|
|
(387
|
)
|
|
Three Months Ended June 30, 2018
|
|
Six Months Ended June 30, 2018
|
||||||||||||||||||||
|
As Reported
|
|
Balances Without Adoption of ASC 606
|
|
Effect of Change: Higher/(Lower)
|
|
As Reported
|
|
Balances Without Adoption of ASC 606
|
|
Effect of Change: Higher/(Lower)
|
||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
1,024
|
|
|
$
|
1,024
|
|
|
$
|
—
|
|
|
$
|
2,086
|
|
|
$
|
2,086
|
|
|
$
|
—
|
|
NGL sales
|
2,141
|
|
|
2,134
|
|
|
7
|
|
|
4,171
|
|
|
4,153
|
|
|
18
|
|
||||||
Crude sales
|
4,241
|
|
|
4,238
|
|
|
3
|
|
|
7,495
|
|
|
7,488
|
|
|
7
|
|
||||||
Gathering, transportation and other fees
|
1,464
|
|
|
1,611
|
|
|
(147
|
)
|
|
2,861
|
|
|
3,194
|
|
|
(333
|
)
|
||||||
Refined product sales
|
413
|
|
|
413
|
|
|
—
|
|
|
852
|
|
|
852
|
|
|
—
|
|
||||||
Other
|
127
|
|
|
127
|
|
|
—
|
|
|
225
|
|
|
225
|
|
|
—
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cost of products sold
|
$
|
7,140
|
|
|
$
|
7,287
|
|
|
$
|
(147
|
)
|
|
$
|
13,128
|
|
|
$
|
13,461
|
|
|
$
|
(333
|
)
|
Operating expenses
|
627
|
|
|
617
|
|
|
10
|
|
|
1,231
|
|
|
1,206
|
|
|
25
|
|
2.
|
ACQUISITIONS AND OTHER INVESTING TRANSACTIONS
|
3.
|
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES
|
4.
|
CASH AND CASH EQUIVALENTS
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017*
|
||||
Accounts receivable
|
$
|
236
|
|
|
$
|
88
|
|
Accounts receivable from related companies
|
156
|
|
|
(115
|
)
|
||
Inventories
|
299
|
|
|
160
|
|
||
Other current assets
|
(375
|
)
|
|
77
|
|
||
Other non-current assets, net
|
(3
|
)
|
|
(39
|
)
|
||
Accounts payable
|
(465
|
)
|
|
(286
|
)
|
||
Accounts payable to related companies
|
(99
|
)
|
|
131
|
|
||
Accrued and other current liabilities
|
249
|
|
|
(389
|
)
|
||
Other non-current liabilities
|
(2
|
)
|
|
7
|
|
||
Derivative assets and liabilities, net
|
233
|
|
|
(21
|
)
|
||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations
|
$
|
229
|
|
|
$
|
(387
|
)
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
NON-CASH INVESTING ACTIVITIES:
|
|
|
|
||||
Accrued capital expenditures
|
$
|
1,007
|
|
|
$
|
1,363
|
|
USAC limited partner interests received in the CDM Contribution (see Note 2)
|
411
|
|
|
—
|
|
||
NON-CASH FINANCING ACTIVITIES:
|
|
|
|
||||
Contribution of property, plant and equipment from noncontrolling interest
|
$
|
—
|
|
|
$
|
988
|
|
5.
|
INVENTORIES
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Natural gas, NGLs and refined products
|
$
|
434
|
|
|
$
|
733
|
|
Crude oil
|
571
|
|
|
551
|
|
||
Spare parts and other
|
251
|
|
|
305
|
|
||
Total inventories
|
$
|
1,256
|
|
|
$
|
1,589
|
|
6.
|
FAIR VALUE MEASURES
|
|
|
|
Fair Value Measurements at
June 30, 2018 |
||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
||||||
Assets:
|
|
|
|
|
|
||||||
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
$
|
22
|
|
|
$
|
22
|
|
|
$
|
—
|
|
Swing Swaps IFERC
|
1
|
|
|
—
|
|
|
1
|
|
|||
Fixed Swaps/Futures
|
11
|
|
|
11
|
|
|
—
|
|
|||
Forward Physical Contracts
|
9
|
|
|
—
|
|
|
9
|
|
|||
Power:
|
|
|
|
|
|
||||||
Forwards
|
69
|
|
|
—
|
|
|
69
|
|
|||
Options – Puts
|
1
|
|
|
1
|
|
|
—
|
|
|||
NGLs – Forwards/Swaps
|
300
|
|
|
300
|
|
|
—
|
|
|||
Total commodity derivatives
|
413
|
|
|
334
|
|
|
79
|
|
|||
Other non-current assets
|
21
|
|
|
14
|
|
|
7
|
|
|||
Total assets
|
$
|
434
|
|
|
$
|
348
|
|
|
$
|
86
|
|
Liabilities:
|
|
|
|
|
|
||||||
Interest rate derivatives
|
$
|
(147
|
)
|
|
$
|
—
|
|
|
$
|
(147
|
)
|
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
(70
|
)
|
|
(70
|
)
|
|
—
|
|
|||
Swing Swaps IFERC
|
(2
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|||
Fixed Swaps/Futures
|
(14
|
)
|
|
(14
|
)
|
|
—
|
|
|||
Forward Physical Contracts
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
|||
Power – Forwards
|
(57
|
)
|
|
—
|
|
|
(57
|
)
|
|||
NGLs – Forwards/Swaps
|
(316
|
)
|
|
(316
|
)
|
|
—
|
|
|||
Refined Products – Futures
|
(5
|
)
|
|
(5
|
)
|
|
—
|
|
|||
Crude – Forwards/Swaps
|
(307
|
)
|
|
(307
|
)
|
|
—
|
|
|||
Total commodity derivatives
|
(776
|
)
|
|
(713
|
)
|
|
(63
|
)
|
|||
Total liabilities
|
$
|
(923
|
)
|
|
$
|
(713
|
)
|
|
$
|
(210
|
)
|
|
|
|
Fair Value Measurements at
December 31, 2017 |
||||||||
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
||||||
Assets:
|
|
|
|
|
|
||||||
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
—
|
|
Swing Swaps IFERC
|
13
|
|
|
—
|
|
|
13
|
|
|||
Fixed Swaps/Futures
|
70
|
|
|
70
|
|
|
—
|
|
|||
Forward Physical Swaps
|
8
|
|
|
—
|
|
|
8
|
|
|||
Power – Forwards
|
23
|
|
|
—
|
|
|
23
|
|
|||
NGLs – Forwards/Swaps
|
191
|
|
|
191
|
|
|
—
|
|
|||
Crude:
|
|
|
|
|
|
||||||
Forwards/Swaps
|
2
|
|
|
2
|
|
|
—
|
|
|||
Futures
|
2
|
|
|
2
|
|
|
—
|
|
|||
Total commodity derivatives
|
320
|
|
|
276
|
|
|
44
|
|
|||
Other non-current assets
|
21
|
|
|
14
|
|
|
7
|
|
|||
Total assets
|
$
|
341
|
|
|
$
|
290
|
|
|
$
|
51
|
|
Liabilities:
|
|
|
|
|
|
||||||
Interest rate derivatives
|
$
|
(219
|
)
|
|
$
|
—
|
|
|
$
|
(219
|
)
|
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
(24
|
)
|
|
(24
|
)
|
|
—
|
|
|||
Swing Swaps IFERC
|
(15
|
)
|
|
(1
|
)
|
|
(14
|
)
|
|||
Fixed Swaps/Futures
|
(57
|
)
|
|
(57
|
)
|
|
—
|
|
|||
Forward Physical Swaps
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|||
Power – Forwards
|
(22
|
)
|
|
—
|
|
|
(22
|
)
|
|||
NGLs – Forwards/Swaps
|
(186
|
)
|
|
(186
|
)
|
|
—
|
|
|||
Refined Products – Futures
|
(25
|
)
|
|
(25
|
)
|
|
—
|
|
|||
Crude:
|
|
|
|
|
|
||||||
Forwards/Swaps
|
(6
|
)
|
|
(6
|
)
|
|
—
|
|
|||
Futures
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Total commodity derivatives
|
(338
|
)
|
|
(300
|
)
|
|
(38
|
)
|
|||
Total liabilities
|
$
|
(557
|
)
|
|
$
|
(300
|
)
|
|
$
|
(257
|
)
|
7.
|
NET INCOME (LOSS) PER LIMITED PARTNER UNIT
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
||||||||
Net income
|
$
|
602
|
|
|
$
|
296
|
|
|
$
|
1,481
|
|
|
$
|
689
|
|
Less: Income attributable to noncontrolling interest
|
170
|
|
|
94
|
|
|
334
|
|
|
156
|
|
||||
Net income, net of noncontrolling interest
|
432
|
|
|
202
|
|
|
1,147
|
|
|
533
|
|
||||
Series A Preferred Unitholders’ interest in net income
|
15
|
|
|
—
|
|
|
30
|
|
|
—
|
|
||||
Series B Preferred Unitholders’ interest in net income
|
9
|
|
|
—
|
|
|
18
|
|
|
—
|
|
||||
Series C Preferred Unitholders’ interest in net income
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
||||
General Partner’s interest in net income
|
402
|
|
|
251
|
|
|
804
|
|
|
457
|
|
||||
Class H Unitholder’s interest in net income
|
—
|
|
|
—
|
|
|
—
|
|
|
93
|
|
||||
Common Unitholders’ interest in net income (loss)
|
—
|
|
|
(49
|
)
|
|
289
|
|
|
(17
|
)
|
||||
Additional (earnings) distributions allocated to General Partner
|
(1
|
)
|
|
15
|
|
|
(3
|
)
|
|
12
|
|
||||
Distributions on employee unit awards, net of allocation to General Partner
|
(7
|
)
|
|
(6
|
)
|
|
(15
|
)
|
|
(13
|
)
|
||||
Net income (loss) available to Common Unitholders
|
$
|
(8
|
)
|
|
$
|
(40
|
)
|
|
$
|
271
|
|
|
$
|
(18
|
)
|
Weighted average Common Units – basic
|
1,165.4
|
|
|
1,021.7
|
|
|
1,164.6
|
|
|
922.5
|
|
||||
Basic net income (loss) per Common Unit
|
$
|
(0.01
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
0.23
|
|
|
$
|
(0.02
|
)
|
|
|
|
|
|
|
|
|
||||||||
Weighted average Common Units – diluted
|
1,165.4
|
|
|
1,021.7
|
|
|
1,169.4
|
|
|
922.5
|
|
||||
Diluted net income (loss) per Common Unit
|
$
|
(0.01
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
0.23
|
|
|
$
|
(0.02
|
)
|
8.
|
DEBT OBLIGATIONS
|
9.
|
EQUITY
|
|
|
Number of Units
|
|
Number of common units at December 31, 2017
|
|
1,164.1
|
|
Common units issued in connection with the distribution reinvestment plan
|
|
2.1
|
|
Common units issued in connection with certain transactions
|
|
1.3
|
|
Issuance of common units under equity incentive plans
|
|
0.1
|
|
Repurchases of common units in open-market transactions
|
|
(1.2
|
)
|
Number of common units at June 30, 2018
|
|
1,166.4
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2017
|
|
February 8, 2018
|
|
February 14, 2018
|
|
$
|
0.5650
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 15, 2018
|
|
0.5650
|
|
|
June 30, 2018
|
|
August 6, 2018
|
|
August 14, 2018
|
|
0.5650
|
|
|
|
Year Ending December 31,
|
||
2018 (remainder)
|
|
$
|
69
|
|
2019
|
|
128
|
|
|
Each year beyond 2019
|
|
33
|
|
Period Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
Series A Preferred Units
|
|
|
|
|
|
|
||
December 31, 2017
|
|
February 1, 2018
|
|
February 15, 2018
|
|
$
|
15.451
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
31.250
|
|
|
Series B Preferred Units
|
|
|
|
|
|
|
||
December 31, 2017
|
|
February 1, 2018
|
|
February 15, 2018
|
|
$
|
16.378
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
33.125
|
|
|
Series C Preferred Units
|
|
|
|
|
|
|
||
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
$
|
0.56337
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Available-for-sale securities
(1)
|
$
|
4
|
|
|
$
|
8
|
|
Foreign currency translation adjustment
|
(5
|
)
|
|
(5
|
)
|
||
Actuarial loss related to pensions and other postretirement benefits
|
(7
|
)
|
|
(5
|
)
|
||
Investments in unconsolidated affiliates, net
|
12
|
|
|
5
|
|
||
Total AOCI, net of tax
|
$
|
4
|
|
|
$
|
3
|
|
(1)
|
Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01,
Recognition and Measurement of Financial Assets and Financial Liabilities
, which resulted in the reclassification of
$2 million
from accumulated other comprehensive income related to available-for-sale securities to common unitholders.
|
10.
|
INCOME TAXES
|
11.
|
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
|
•
|
$1.00 billion
aggregate principal amount of
4.875%
senior notes due 2023;
|
•
|
$800 million
aggregate principal amount of
5.50%
senior notes due 2026; and
|
•
|
$400 million
aggregate principal amount of
5.875%
senior notes due 2028.
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Rental expense
|
$
|
22
|
|
|
$
|
19
|
|
|
$
|
39
|
|
|
$
|
39
|
|
•
|
certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
|
•
|
certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
|
•
|
legacy sites related to 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
June 30, 2018
,
Sunoco, Inc. had been named as a PRP at approximately
41
identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Current
|
$
|
42
|
|
|
$
|
36
|
|
Non-current
|
276
|
|
|
314
|
|
||
Total environmental liabilities
|
$
|
318
|
|
|
$
|
350
|
|
12.
|
REVENUE
|
•
|
intrastate transportation and storage
;
|
•
|
interstate transportation and storage
;
|
•
|
midstream
;
|
•
|
NGL and refined products transportation and services
;
|
•
|
crude oil transportation and services
; and
|
•
|
all other
.
|
•
|
In-Kind POP:
We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.
|
•
|
Mixed POP:
We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.
|
|
|
2018 (remainder)
|
|
2019
|
|
2020
|
|
Thereafter
|
|
Total
|
||||||||||
Revenue expected to be recognized on contracts with customers existing as of June 30, 2018
|
|
$
|
2,598
|
|
|
$
|
5,048
|
|
|
$
|
4,604
|
|
|
$
|
28,071
|
|
|
$
|
40,321
|
|
•
|
Right to invoice:
The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds
|
•
|
Significant financing component:
The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.
|
•
|
Unearned variable consideration:
The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.
|
13.
|
DERIVATIVE ASSETS AND LIABILITIES
|
|
June 30, 2018
|
|
December 31, 2017
|
||||||
|
Notional Volume
|
|
Maturity
|
|
Notional Volume
|
|
Maturity
|
||
Mark-to-Market Derivatives
|
|
|
|
|
|
|
|
||
(Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
||
Fixed Swaps/Futures
|
465
|
|
|
2018
|
|
1,078
|
|
|
2018
|
Basis Swaps IFERC/NYMEX
(1)
|
102,328
|
|
|
2018-2020
|
|
48,510
|
|
|
2018-2020
|
Options – Puts
|
(3,043
|
)
|
|
2018
|
|
13,000
|
|
|
2018
|
Power (Megawatt):
|
|
|
|
|
|
|
|
||
Forwards
|
3,196,100
|
|
|
2018-2019
|
|
435,960
|
|
|
2018-2019
|
Futures
|
(42,768
|
)
|
|
2018
|
|
(25,760
|
)
|
|
2018
|
Options – Puts
|
(30,532
|
)
|
|
2018
|
|
(153,600
|
)
|
|
2018
|
Options – Calls
|
996,172
|
|
|
2018
|
|
137,600
|
|
|
2018
|
(Non-Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
||
Basis Swaps IFERC/NYMEX
|
6,600
|
|
|
2018-2020
|
|
4,650
|
|
|
2018-2020
|
Swing Swaps IFERC
|
52,413
|
|
|
2018-2019
|
|
87,253
|
|
|
2018-2019
|
Fixed Swaps/Futures
|
5,360
|
|
|
2018-2019
|
|
(4,700
|
)
|
|
2018-2019
|
Forward Physical Contracts
|
(174,465
|
)
|
|
2018-2020
|
|
(145,105
|
)
|
|
2018-2020
|
NGL (MBbls) – Forwards/Swaps
|
(1,590
|
)
|
|
2018-2019
|
|
(2,493
|
)
|
|
2018-2019
|
Crude (MBbls) – Forwards/Swaps
|
44,190
|
|
|
2018-2019
|
|
9,172
|
|
|
2018-2019
|
Refined Products (MBbls) – Futures
|
(1,076
|
)
|
|
2018-2019
|
|
(3,783
|
)
|
|
2018-2019
|
Fair Value Hedging Derivatives
|
|
|
|
|
|
|
|
||
(Non-Trading)
|
|
|
|
|
|
|
|
||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
||
Basis Swaps IFERC/NYMEX
|
(21,475
|
)
|
|
2018
|
|
(39,770
|
)
|
|
2018
|
Fixed Swaps/Futures
|
(21,475
|
)
|
|
2018
|
|
(39,770
|
)
|
|
2018
|
Hedged Item – Inventory
|
21,475
|
|
|
2018
|
|
39,770
|
|
|
2018
|
(1)
|
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
|
Term
|
|
Type
(1)
|
|
Notional Amount Outstanding
|
||||||
June 30, 2018
|
|
December 31, 2017
|
||||||||
July 2018
(2)
|
|
Forward-starting to pay a fixed rate of 3.76% and receive a floating rate
|
|
$
|
—
|
|
|
$
|
300
|
|
July 2019
(2)
|
|
Forward-starting to pay a fixed rate of 3.56% and receive a floating rate
|
|
400
|
|
|
300
|
|
||
July 2020
(2)
|
|
Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
|
|
400
|
|
|
400
|
|
||
July 2021
(2)
|
|
Forward-starting to pay a fixed rate of 3.55% and receive a floating rate
|
|
400
|
|
|
—
|
|
||
December 2018
|
|
Pay a floating rate 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 30 years with a mandatory termination date the same as the effective date.
|
|
|
Fair Value of Derivative Instruments
|
||||||||||||||
|
|
Asset Derivatives
|
|
Liability Derivatives
|
||||||||||||
|
|
June 30, 2018
|
|
December 31, 2017
|
|
June 30, 2018
|
|
December 31, 2017
|
||||||||
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives (margin deposits)
|
|
$
|
—
|
|
|
$
|
14
|
|
|
$
|
(2
|
)
|
|
$
|
(2
|
)
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives (margin deposits)
|
|
307
|
|
|
262
|
|
|
(352
|
)
|
|
(281
|
)
|
||||
Commodity derivatives
|
|
106
|
|
|
44
|
|
|
(422
|
)
|
|
(55
|
)
|
||||
Interest rate derivatives
|
|
—
|
|
|
—
|
|
|
(147
|
)
|
|
(219
|
)
|
||||
|
|
413
|
|
|
306
|
|
|
(921
|
)
|
|
(555
|
)
|
||||
Total derivatives
|
|
$
|
413
|
|
|
$
|
320
|
|
|
$
|
(923
|
)
|
|
$
|
(557
|
)
|
|
Location of Gain/(Loss) Recognized in Income on Derivatives
|
|
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
|
||||||||||||||
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Derivatives in fair value hedging relationships (including hedged item):
|
|
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives
|
Cost of products sold
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
9
|
|
|
$
|
2
|
|
|
Location of Gain/(Loss) Recognized in Income on Derivatives
|
|
Amount of Gain/(Loss) Recognized in Income on Derivatives
|
||||||||||||||
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives – Trading
|
Cost of products sold
|
|
$
|
16
|
|
|
$
|
15
|
|
|
$
|
33
|
|
|
$
|
26
|
|
Commodity derivatives – Non-trading
|
Cost of products sold
|
|
(300
|
)
|
|
7
|
|
|
(373
|
)
|
|
(3
|
)
|
||||
Interest rate derivatives
|
Gains (losses) on interest rate derivatives
|
|
20
|
|
|
(25
|
)
|
|
72
|
|
|
(20
|
)
|
||||
Embedded derivatives
|
Other, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Total
|
|
|
$
|
(264
|
)
|
|
$
|
(3
|
)
|
|
$
|
(268
|
)
|
|
$
|
4
|
|
14.
|
RELATED PARTY TRANSACTIONS
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Affiliated revenues
|
$
|
222
|
|
|
$
|
133
|
|
|
$
|
508
|
|
|
$
|
251
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Accounts receivable from related companies:
|
|
|
|
||||
Sunoco LP
|
$
|
184
|
|
|
$
|
219
|
|
FGT
|
18
|
|
|
11
|
|
||
Other
|
132
|
|
|
88
|
|
||
Total accounts receivable from related companies:
|
$
|
334
|
|
|
$
|
318
|
|
|
|
|
|
||||
Accounts payable to related companies:
|
|
|
|
||||
Sunoco LP
|
$
|
195
|
|
|
$
|
195
|
|
USAC
|
45
|
|
|
—
|
|
||
Other
|
89
|
|
|
14
|
|
||
Total accounts payable to related companies:
|
$
|
329
|
|
|
$
|
209
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Long-term notes receivable from related company:
|
|
|
|
||||
Sunoco LP
|
$
|
85
|
|
|
$
|
85
|
|
15.
|
REPORTABLE SEGMENTS
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Revenues:
|
|
|
|
|
|
|
|
||||||||
Intrastate transportation and storage:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
$
|
761
|
|
|
$
|
699
|
|
|
$
|
1,578
|
|
|
$
|
1,467
|
|
Intersegment revenues
|
52
|
|
|
54
|
|
|
110
|
|
|
102
|
|
||||
|
813
|
|
|
753
|
|
|
1,688
|
|
|
1,569
|
|
||||
Interstate transportation and storage:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
323
|
|
|
201
|
|
|
636
|
|
|
432
|
|
||||
Intersegment revenues
|
5
|
|
|
6
|
|
|
8
|
|
|
10
|
|
||||
|
328
|
|
|
207
|
|
|
644
|
|
|
442
|
|
||||
Midstream:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
594
|
|
|
633
|
|
|
1,034
|
|
|
1,198
|
|
||||
Intersegment revenues
|
1,280
|
|
|
982
|
|
|
2,454
|
|
|
2,054
|
|
||||
|
1,874
|
|
|
1,615
|
|
|
3,488
|
|
|
3,252
|
|
||||
NGL and refined products transportation and services:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
2,472
|
|
|
1,767
|
|
|
4,930
|
|
|
3,885
|
|
||||
Intersegment revenues
|
96
|
|
|
12
|
|
|
184
|
|
|
160
|
|
||||
|
2,568
|
|
|
1,779
|
|
|
5,114
|
|
|
4,045
|
|
||||
Crude oil transportation and services:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
4,789
|
|
|
2,460
|
|
|
8,520
|
|
|
5,035
|
|
||||
Intersegment revenues
|
14
|
|
|
5
|
|
|
28
|
|
|
5
|
|
||||
|
4,803
|
|
|
2,465
|
|
|
8,548
|
|
|
5,040
|
|
||||
All other:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
471
|
|
|
816
|
|
|
992
|
|
|
1,454
|
|
||||
Intersegment revenues
|
31
|
|
|
54
|
|
|
81
|
|
|
186
|
|
||||
|
502
|
|
|
870
|
|
|
1,073
|
|
|
1,640
|
|
||||
Eliminations
|
(1,478
|
)
|
|
(1,113
|
)
|
|
(2,865
|
)
|
|
(2,517
|
)
|
||||
Total revenues
|
$
|
9,410
|
|
|
$
|
6,576
|
|
|
$
|
17,690
|
|
|
$
|
13,471
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
||||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
|
|
||||||||
Intrastate transportation and storage
|
$
|
208
|
|
|
$
|
148
|
|
|
$
|
400
|
|
|
$
|
317
|
|
Interstate transportation and storage
|
330
|
|
|
262
|
|
|
653
|
|
|
527
|
|
||||
Midstream
|
414
|
|
|
412
|
|
|
791
|
|
|
732
|
|
||||
NGL and refined products transportation and services
|
461
|
|
|
388
|
|
|
912
|
|
|
769
|
|
||||
Crude oil transportation and services
|
548
|
|
|
228
|
|
|
1,012
|
|
|
415
|
|
||||
All other
|
90
|
|
|
107
|
|
|
164
|
|
|
230
|
|
||||
Total
|
2,051
|
|
|
1,545
|
|
|
3,932
|
|
|
2,990
|
|
||||
Depreciation, depletion and amortization
|
(588
|
)
|
|
(557
|
)
|
|
(1,191
|
)
|
|
(1,117
|
)
|
||||
Interest expense, net
|
(358
|
)
|
|
(336
|
)
|
|
(704
|
)
|
|
(668
|
)
|
||||
Gain on Sunoco LP common unit repurchase
|
—
|
|
|
—
|
|
|
172
|
|
|
—
|
|
||||
Loss on deconsolidation of CDM
|
(86
|
)
|
|
—
|
|
|
(86
|
)
|
|
—
|
|
||||
Gains (losses) on interest rate derivatives
|
20
|
|
|
(25
|
)
|
|
72
|
|
|
(20
|
)
|
||||
Non-cash compensation expense
|
(21
|
)
|
|
(15
|
)
|
|
(41
|
)
|
|
(38
|
)
|
||||
Unrealized gains (losses) on commodity risk management activities
|
(265
|
)
|
|
34
|
|
|
(352
|
)
|
|
98
|
|
||||
Adjusted EBITDA related to unconsolidated affiliates
|
(228
|
)
|
|
(247
|
)
|
|
(413
|
)
|
|
(486
|
)
|
||||
Equity in earnings (losses) of unconsolidated affiliates
|
106
|
|
|
(61
|
)
|
|
34
|
|
|
12
|
|
||||
Other, net
|
40
|
|
|
37
|
|
|
87
|
|
|
52
|
|
||||
Income before income tax expense
|
$
|
671
|
|
|
$
|
375
|
|
|
$
|
1,510
|
|
|
$
|
823
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Assets:
|
|
|
|
||||
Intrastate transportation and storage
|
$
|
5,604
|
|
|
$
|
5,020
|
|
Interstate transportation and storage
|
14,037
|
|
|
13,518
|
|
||
Midstream
|
19,949
|
|
|
20,004
|
|
||
NGL and refined products transportation and services
|
17,517
|
|
|
17,600
|
|
||
Crude oil transportation and services
|
18,168
|
|
|
17,736
|
|
||
All other
|
3,295
|
|
|
4,087
|
|
||
Total assets
|
$
|
78,570
|
|
|
$
|
77,965
|
|
16.
|
CONSOLIDATING GUARANTOR FINANCIAL INFORMATION
|
|
June 30, 2018
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
494
|
|
|
$
|
—
|
|
|
$
|
494
|
|
All other current assets
|
—
|
|
|
57
|
|
|
8,527
|
|
|
(2,531
|
)
|
|
6,053
|
|
|||||
Property, plant and equipment, net
|
—
|
|
|
—
|
|
|
59,776
|
|
|
—
|
|
|
59,776
|
|
|||||
Investments in unconsolidated affiliates
|
51,199
|
|
|
12,078
|
|
|
3,636
|
|
|
(63,277
|
)
|
|
3,636
|
|
|||||
All other assets
|
8
|
|
|
—
|
|
|
8,603
|
|
|
—
|
|
|
8,611
|
|
|||||
Total assets
|
$
|
51,207
|
|
|
$
|
12,135
|
|
|
$
|
81,036
|
|
|
$
|
(65,808
|
)
|
|
$
|
78,570
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
$
|
390
|
|
|
$
|
(3,571
|
)
|
|
$
|
12,353
|
|
|
$
|
(2,531
|
)
|
|
$
|
6,641
|
|
Non-current liabilities
|
22,949
|
|
|
7,606
|
|
|
7,338
|
|
|
—
|
|
|
37,893
|
|
|||||
Noncontrolling interest
|
—
|
|
|
—
|
|
|
6,171
|
|
|
—
|
|
|
6,171
|
|
|||||
Total partners’ capital
|
27,868
|
|
|
8,100
|
|
|
55,174
|
|
|
(63,277
|
)
|
|
27,865
|
|
|||||
Total liabilities and equity
|
$
|
51,207
|
|
|
$
|
12,135
|
|
|
$
|
81,036
|
|
|
$
|
(65,808
|
)
|
|
$
|
78,570
|
|
|
December 31, 2017
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
$
|
309
|
|
|
$
|
—
|
|
|
$
|
306
|
|
All other current assets
|
—
|
|
|
159
|
|
|
6,063
|
|
|
—
|
|
|
6,222
|
|
|||||
Property, plant and equipment, net
|
—
|
|
|
—
|
|
|
58,437
|
|
|
—
|
|
|
58,437
|
|
|||||
Investments in unconsolidated affiliates
|
48,378
|
|
|
11,648
|
|
|
3,816
|
|
|
(60,026
|
)
|
|
3,816
|
|
|||||
All other assets
|
—
|
|
|
—
|
|
|
9,184
|
|
|
—
|
|
|
9,184
|
|
|||||
Total assets
|
$
|
48,378
|
|
|
$
|
11,804
|
|
|
$
|
77,809
|
|
|
$
|
(60,026
|
)
|
|
$
|
77,965
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
$
|
(1,496
|
)
|
|
$
|
(3,660
|
)
|
|
$
|
12,150
|
|
|
$
|
—
|
|
|
$
|
6,994
|
|
Non-current liabilities
|
21,604
|
|
|
7,607
|
|
|
7,609
|
|
|
—
|
|
|
36,820
|
|
|||||
Noncontrolling interest
|
—
|
|
|
—
|
|
|
5,882
|
|
|
—
|
|
|
5,882
|
|
|||||
Total partners’ capital
|
28,270
|
|
|
7,857
|
|
|
52,168
|
|
|
(60,026
|
)
|
|
28,269
|
|
|||||
Total liabilities and equity
|
$
|
48,378
|
|
|
$
|
11,804
|
|
|
$
|
77,809
|
|
|
$
|
(60,026
|
)
|
|
$
|
77,965
|
|
|
Three Months Ended June 30, 2018
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,410
|
|
|
$
|
—
|
|
|
$
|
9,410
|
|
Operating costs, expenses, and other
|
—
|
|
|
—
|
|
|
8,467
|
|
|
—
|
|
|
8,467
|
|
|||||
Operating income
|
—
|
|
|
—
|
|
|
943
|
|
|
—
|
|
|
943
|
|
|||||
Interest expense, net
|
(289
|
)
|
|
(41
|
)
|
|
(28
|
)
|
|
—
|
|
|
(358
|
)
|
|||||
Equity in earnings of unconsolidated affiliates
|
701
|
|
|
66
|
|
|
106
|
|
|
(767
|
)
|
|
106
|
|
|||||
Gains on interest rate derivatives
|
20
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|||||
Loss on deconsolidation of CDM
|
—
|
|
|
—
|
|
|
(86
|
)
|
|
—
|
|
|
(86
|
)
|
|||||
Other, net
|
—
|
|
|
—
|
|
|
46
|
|
|
—
|
|
|
46
|
|
|||||
Income before income tax expense
|
432
|
|
|
25
|
|
|
981
|
|
|
(767
|
)
|
|
671
|
|
|||||
Income tax expense
|
—
|
|
|
—
|
|
|
69
|
|
|
—
|
|
|
69
|
|
|||||
Net income
|
432
|
|
|
25
|
|
|
912
|
|
|
(767
|
)
|
|
602
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
170
|
|
|
—
|
|
|
170
|
|
|||||
Net income attributable to partners
|
$
|
432
|
|
|
$
|
25
|
|
|
$
|
742
|
|
|
$
|
(767
|
)
|
|
$
|
432
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other comprehensive income
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Comprehensive income
|
432
|
|
|
25
|
|
|
914
|
|
|
(767
|
)
|
|
604
|
|
|||||
Comprehensive income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
170
|
|
|
—
|
|
|
170
|
|
|||||
Comprehensive income attributable to partners
|
$
|
432
|
|
|
$
|
25
|
|
|
$
|
744
|
|
|
$
|
(767
|
)
|
|
$
|
434
|
|
|
Three Months Ended June 30, 2017*
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6,576
|
|
|
$
|
—
|
|
|
$
|
6,576
|
|
Operating costs, expenses, and other
|
—
|
|
|
1
|
|
|
5,839
|
|
|
—
|
|
|
5,840
|
|
|||||
Operating income (loss)
|
—
|
|
|
(1
|
)
|
|
737
|
|
|
—
|
|
|
736
|
|
|||||
Interest expense, net
|
—
|
|
|
(39
|
)
|
|
(297
|
)
|
|
—
|
|
|
(336
|
)
|
|||||
Equity in earnings (losses) of unconsolidated affiliates
|
199
|
|
|
137
|
|
|
(61
|
)
|
|
(336
|
)
|
|
(61
|
)
|
|||||
Losses on interest rate derivatives
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
(25
|
)
|
|||||
Other, net
|
—
|
|
|
3
|
|
|
59
|
|
|
(1
|
)
|
|
61
|
|
|||||
Income before income tax expense
|
199
|
|
|
100
|
|
|
413
|
|
|
(337
|
)
|
|
375
|
|
|||||
Income tax expense
|
—
|
|
|
—
|
|
|
79
|
|
|
—
|
|
|
79
|
|
|||||
Net income
|
199
|
|
|
100
|
|
|
334
|
|
|
(337
|
)
|
|
296
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
94
|
|
|
—
|
|
|
94
|
|
|||||
Net income attributable to partners
|
$
|
199
|
|
|
$
|
100
|
|
|
$
|
240
|
|
|
$
|
(337
|
)
|
|
$
|
202
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other comprehensive loss
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
Comprehensive income
|
199
|
|
|
100
|
|
|
333
|
|
|
(337
|
)
|
|
295
|
|
|||||
Comprehensive income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
94
|
|
|
—
|
|
|
94
|
|
|||||
Comprehensive income attributable to partners
|
$
|
199
|
|
|
$
|
100
|
|
|
$
|
239
|
|
|
$
|
(337
|
)
|
|
$
|
201
|
|
|
Six Months Ended June 30, 2018
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
17,690
|
|
|
$
|
—
|
|
|
$
|
17,690
|
|
Operating costs, expenses, and other
|
—
|
|
|
—
|
|
|
15,774
|
|
|
—
|
|
|
15,774
|
|
|||||
Operating income
|
—
|
|
|
—
|
|
|
1,916
|
|
|
—
|
|
|
1,916
|
|
|||||
Interest expense, net
|
(567
|
)
|
|
(82
|
)
|
|
(55
|
)
|
|
—
|
|
|
(704
|
)
|
|||||
Equity in earnings of unconsolidated affiliates
|
1,642
|
|
|
326
|
|
|
34
|
|
|
(1,968
|
)
|
|
34
|
|
|||||
Gains on interest rate derivatives
|
72
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
72
|
|
|||||
Gain on Sunoco LP unit repurchase
|
—
|
|
|
—
|
|
|
172
|
|
|
—
|
|
|
172
|
|
|||||
Loss on deconsolidation of CDM
|
—
|
|
|
—
|
|
|
(86
|
)
|
|
—
|
|
|
(86
|
)
|
|||||
Other, net
|
—
|
|
|
—
|
|
|
106
|
|
|
—
|
|
|
106
|
|
|||||
Income before income tax expense
|
1,147
|
|
|
244
|
|
|
2,087
|
|
|
(1,968
|
)
|
|
1,510
|
|
|||||
Income tax expense
|
—
|
|
|
—
|
|
|
29
|
|
|
—
|
|
|
29
|
|
|||||
Net income
|
1,147
|
|
|
244
|
|
|
2,058
|
|
|
(1,968
|
)
|
|
1,481
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
334
|
|
|
—
|
|
|
334
|
|
|||||
Net income attributable to partners
|
$
|
1,147
|
|
|
$
|
244
|
|
|
$
|
1,724
|
|
|
$
|
(1,968
|
)
|
|
$
|
1,147
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other comprehensive income
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
3
|
|
Comprehensive income
|
1,147
|
|
|
244
|
|
|
2,061
|
|
|
(1,968
|
)
|
|
1,484
|
|
|||||
Comprehensive income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
334
|
|
|
—
|
|
|
334
|
|
|||||
Comprehensive income attributable to partners
|
$
|
1,147
|
|
|
$
|
244
|
|
|
$
|
1,727
|
|
|
$
|
(1,968
|
)
|
|
$
|
1,150
|
|
|
Six Months Ended June 30, 2017*
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
13,471
|
|
|
$
|
—
|
|
|
$
|
13,471
|
|
Operating costs, expenses, and other
|
—
|
|
|
1
|
|
|
12,051
|
|
|
—
|
|
|
12,052
|
|
|||||
Operating income (loss)
|
—
|
|
|
(1
|
)
|
|
1,420
|
|
|
—
|
|
|
1,419
|
|
|||||
Interest expense, net
|
—
|
|
|
(81
|
)
|
|
(587
|
)
|
|
—
|
|
|
(668
|
)
|
|||||
Equity in earnings of unconsolidated affiliates
|
1,010
|
|
|
765
|
|
|
12
|
|
|
(1,775
|
)
|
|
12
|
|
|||||
Losses on interest rate derivatives
|
—
|
|
|
—
|
|
|
(20
|
)
|
|
—
|
|
|
(20
|
)
|
|||||
Other, net
|
—
|
|
|
3
|
|
|
78
|
|
|
(1
|
)
|
|
80
|
|
|||||
Income before income tax expense
|
1,010
|
|
|
686
|
|
|
903
|
|
|
(1,776
|
)
|
|
823
|
|
|||||
Income tax expense
|
—
|
|
|
—
|
|
|
134
|
|
|
—
|
|
|
134
|
|
|||||
Net income
|
1,010
|
|
|
686
|
|
|
769
|
|
|
(1,776
|
)
|
|
689
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
156
|
|
|
—
|
|
|
156
|
|
|||||
Net income attributable to partners
|
$
|
1,010
|
|
|
$
|
686
|
|
|
$
|
613
|
|
|
$
|
(1,776
|
)
|
|
$
|
533
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other comprehensive loss
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
Comprehensive income
|
1,010
|
|
|
686
|
|
|
768
|
|
|
(1,776
|
)
|
|
688
|
|
|||||
Comprehensive income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
156
|
|
|
—
|
|
|
156
|
|
|||||
Comprehensive income attributable to partners
|
$
|
1,010
|
|
|
$
|
686
|
|
|
$
|
612
|
|
|
$
|
(1,776
|
)
|
|
$
|
532
|
|
|
Six Months Ended June 30, 2018
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash flows provided by operating activities
|
$
|
3,252
|
|
|
$
|
102
|
|
|
$
|
585
|
|
|
$
|
(989
|
)
|
|
$
|
2,950
|
|
Cash flows used in investing activities
|
(2,925
|
)
|
|
(99
|
)
|
|
(903
|
)
|
|
2,336
|
|
|
(1,591
|
)
|
|||||
Cash flows provided by (used in) financing activities
|
(327
|
)
|
|
—
|
|
|
503
|
|
|
(1,347
|
)
|
|
(1,171
|
)
|
|||||
Change in cash
|
—
|
|
|
3
|
|
|
185
|
|
|
—
|
|
|
188
|
|
|||||
Cash at beginning of period
|
—
|
|
|
(3
|
)
|
|
309
|
|
|
—
|
|
|
306
|
|
|||||
Cash at end of period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
494
|
|
|
$
|
—
|
|
|
$
|
494
|
|
|
Six Months Ended June 30, 2017
|
||||||||||||||||||
|
Parent Guarantor
|
|
Subsidiary Issuer
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated Partnership
|
||||||||||
Cash flows provided by operating activities
|
$
|
1,010
|
|
|
$
|
652
|
|
|
$
|
1,764
|
|
|
$
|
(1,776
|
)
|
|
$
|
1,650
|
|
Cash flows used in investing activities
|
(716
|
)
|
|
(421
|
)
|
|
(2,125
|
)
|
|
1,776
|
|
|
(1,486
|
)
|
|||||
Cash flows provided by (used in) financing activities
|
(294
|
)
|
|
(249
|
)
|
|
291
|
|
|
—
|
|
|
(252
|
)
|
|||||
Change in cash
|
—
|
|
|
(18
|
)
|
|
(70
|
)
|
|
—
|
|
|
(88
|
)
|
|||||
Cash at beginning of period
|
—
|
|
|
41
|
|
|
319
|
|
|
—
|
|
|
360
|
|
|||||
Cash at end of period
|
$
|
—
|
|
|
$
|
23
|
|
|
$
|
249
|
|
|
$
|
—
|
|
|
$
|
272
|
|
•
|
Natural gas operations, including the following:
|
•
|
natural gas midstream and intrastate transportation and storage; and
|
•
|
interstate natural gas transportation and storage.
|
•
|
Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017*
|
|
Change
|
|
2018
|
|
2017*
|
|
Change
|
||||||||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Intrastate transportation and storage
|
$
|
208
|
|
|
$
|
148
|
|
|
$
|
60
|
|
|
$
|
400
|
|
|
$
|
317
|
|
|
$
|
83
|
|
Interstate transportation and storage
|
330
|
|
|
262
|
|
|
68
|
|
|
653
|
|
|
527
|
|
|
126
|
|
||||||
Midstream
|
414
|
|
|
412
|
|
|
2
|
|
|
791
|
|
|
732
|
|
|
59
|
|
||||||
NGL and refined products transportation and services
|
461
|
|
|
388
|
|
|
73
|
|
|
912
|
|
|
769
|
|
|
143
|
|
||||||
Crude oil transportation and services
|
548
|
|
|
228
|
|
|
320
|
|
|
1,012
|
|
|
415
|
|
|
597
|
|
||||||
All other
|
90
|
|
|
107
|
|
|
(17
|
)
|
|
164
|
|
|
230
|
|
|
(66
|
)
|
||||||
Total
|
2,051
|
|
|
1,545
|
|
|
506
|
|
|
3,932
|
|
|
2,990
|
|
|
942
|
|
||||||
Depreciation, depletion and amortization
|
(588
|
)
|
|
(557
|
)
|
|
(31
|
)
|
|
(1,191
|
)
|
|
(1,117
|
)
|
|
(74
|
)
|
||||||
Interest expense, net
|
(358
|
)
|
|
(336
|
)
|
|
(22
|
)
|
|
(704
|
)
|
|
(668
|
)
|
|
(36
|
)
|
||||||
Gain on Sunoco LP common unit repurchase
|
—
|
|
|
—
|
|
|
—
|
|
|
172
|
|
|
—
|
|
|
172
|
|
||||||
Loss on deconsolidation of CDM
|
(86
|
)
|
|
—
|
|
|
(86
|
)
|
|
(86
|
)
|
|
—
|
|
|
(86
|
)
|
||||||
Gains (losses) on interest rate derivatives
|
20
|
|
|
(25
|
)
|
|
45
|
|
|
72
|
|
|
(20
|
)
|
|
92
|
|
||||||
Non-cash compensation expense
|
(21
|
)
|
|
(15
|
)
|
|
(6
|
)
|
|
(41
|
)
|
|
(38
|
)
|
|
(3
|
)
|
||||||
Unrealized gains (losses) on commodity risk management activities
|
(265
|
)
|
|
34
|
|
|
(299
|
)
|
|
(352
|
)
|
|
98
|
|
|
(450
|
)
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
|
(228
|
)
|
|
(247
|
)
|
|
19
|
|
|
(413
|
)
|
|
(486
|
)
|
|
73
|
|
||||||
Equity in earnings (losses) of unconsolidated affiliates
|
106
|
|
|
(61
|
)
|
|
167
|
|
|
34
|
|
|
12
|
|
|
22
|
|
||||||
Other, net
|
40
|
|
|
37
|
|
|
3
|
|
|
87
|
|
|
52
|
|
|
35
|
|
||||||
Income before income tax expense
|
671
|
|
|
375
|
|
|
296
|
|
|
1,510
|
|
|
823
|
|
|
687
|
|
||||||
Income tax expense
|
(69
|
)
|
|
(79
|
)
|
|
10
|
|
|
(29
|
)
|
|
(134
|
)
|
|
105
|
|
||||||
Net income
|
$
|
602
|
|
|
$
|
296
|
|
|
$
|
306
|
|
|
$
|
1,481
|
|
|
$
|
689
|
|
|
$
|
792
|
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Equity in earnings (losses) of unconsolidated affiliates:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Citrus
|
$
|
33
|
|
|
$
|
30
|
|
|
$
|
3
|
|
|
$
|
60
|
|
|
$
|
51
|
|
|
$
|
9
|
|
FEP
|
13
|
|
|
13
|
|
|
—
|
|
|
27
|
|
|
25
|
|
|
2
|
|
||||||
MEP
|
8
|
|
|
10
|
|
|
(2
|
)
|
|
17
|
|
|
20
|
|
|
(3
|
)
|
||||||
Sunoco LP
|
16
|
|
|
(110
|
)
|
|
126
|
|
|
(135
|
)
|
|
(124
|
)
|
|
(11
|
)
|
||||||
USAC
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
||||||
Other
|
38
|
|
|
(4
|
)
|
|
42
|
|
|
67
|
|
|
40
|
|
|
27
|
|
||||||
Total equity in earnings (losses) of unconsolidated affiliates
|
$
|
106
|
|
|
$
|
(61
|
)
|
|
$
|
167
|
|
|
$
|
34
|
|
|
$
|
12
|
|
|
$
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Adjusted EBITDA related to unconsolidated affiliates
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Citrus
|
$
|
85
|
|
|
$
|
88
|
|
|
$
|
(3
|
)
|
|
$
|
160
|
|
|
$
|
163
|
|
|
$
|
(3
|
)
|
FEP
|
18
|
|
|
19
|
|
|
(1
|
)
|
|
37
|
|
|
37
|
|
|
—
|
|
||||||
MEP
|
20
|
|
|
21
|
|
|
(1
|
)
|
|
42
|
|
|
43
|
|
|
(1
|
)
|
||||||
Sunoco LP
|
39
|
|
|
83
|
|
|
(44
|
)
|
|
68
|
|
|
137
|
|
|
(69
|
)
|
||||||
USAC
|
21
|
|
|
—
|
|
|
21
|
|
|
21
|
|
|
—
|
|
|
21
|
|
||||||
Other
|
45
|
|
|
36
|
|
|
9
|
|
|
85
|
|
|
106
|
|
|
(21
|
)
|
||||||
Total Adjusted EBITDA related to unconsolidated affiliates
|
$
|
228
|
|
|
$
|
247
|
|
|
$
|
(19
|
)
|
|
$
|
413
|
|
|
$
|
486
|
|
|
$
|
(73
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Distributions received from unconsolidated affiliates:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Citrus
|
$
|
27
|
|
|
$
|
22
|
|
|
$
|
5
|
|
|
$
|
73
|
|
|
$
|
63
|
|
|
$
|
10
|
|
FEP
|
15
|
|
|
10
|
|
|
5
|
|
|
32
|
|
|
10
|
|
|
22
|
|
||||||
MEP
|
18
|
|
|
20
|
|
|
(2
|
)
|
|
31
|
|
|
93
|
|
|
(62
|
)
|
||||||
Sunoco LP
|
22
|
|
|
37
|
|
|
(15
|
)
|
|
58
|
|
|
72
|
|
|
(14
|
)
|
||||||
USAC
|
10
|
|
|
—
|
|
|
10
|
|
|
10
|
|
|
—
|
|
|
10
|
|
||||||
Other
|
21
|
|
|
30
|
|
|
(9
|
)
|
|
42
|
|
|
53
|
|
|
(11
|
)
|
||||||
Total distributions received from unconsolidated affiliates
|
$
|
113
|
|
|
$
|
119
|
|
|
$
|
(6
|
)
|
|
$
|
246
|
|
|
$
|
291
|
|
|
$
|
(45
|
)
|
(1)
|
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
|
•
|
Segment 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
. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
|
•
|
Non-cash compensation expense
. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
|
•
|
Adjusted EBITDA related to unconsolidated affiliates
. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Intrastate transportation and storage
|
$
|
267
|
|
|
$
|
202
|
|
|
$
|
438
|
|
|
$
|
384
|
|
Interstate transportation and storage
|
328
|
|
|
207
|
|
|
644
|
|
|
$
|
442
|
|
|||
Midstream
|
593
|
|
|
571
|
|
|
1,146
|
|
|
1,084
|
|
||||
NGL and refined products transportation and services
|
587
|
|
|
516
|
|
|
1,187
|
|
|
1,075
|
|
||||
Crude oil transportation and services
|
442
|
|
|
374
|
|
|
1,010
|
|
|
646
|
|
||||
All other
|
57
|
|
|
76
|
|
|
152
|
|
|
178
|
|
||||
Intersegment eliminations
|
(4
|
)
|
|
6
|
|
|
(15
|
)
|
|
(12
|
)
|
||||
Total segment margin
|
2,270
|
|
|
1,952
|
|
|
4,562
|
|
|
3,797
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Less:
|
|
|
|
|
|
|
|
||||||||
Operating expenses
|
627
|
|
|
539
|
|
|
1,231
|
|
|
1,031
|
|
||||
Depreciation, depletion and amortization
|
588
|
|
|
557
|
|
|
1,191
|
|
|
1,117
|
|
||||
Selling, general and administrative
|
112
|
|
|
120
|
|
|
224
|
|
|
230
|
|
||||
Operating income
|
$
|
943
|
|
|
$
|
736
|
|
|
$
|
1,916
|
|
|
$
|
1,419
|
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Natural gas transported (BBtu/d)
|
10,327
|
|
|
9,261
|
|
|
1,066
|
|
|
9,802
|
|
|
8,569
|
|
|
1,233
|
|
||||||
Withdrawals from storage natural gas inventory (BBtu)
|
—
|
|
|
—
|
|
|
—
|
|
|
17,703
|
|
|
23,093
|
|
|
(5,390
|
)
|
||||||
Revenues
|
$
|
813
|
|
|
$
|
753
|
|
|
$
|
60
|
|
|
$
|
1,688
|
|
|
$
|
1,569
|
|
|
$
|
119
|
|
Cost of products sold
|
546
|
|
|
551
|
|
|
(5
|
)
|
|
1,250
|
|
|
1,185
|
|
|
65
|
|
||||||
Segment margin
|
267
|
|
|
202
|
|
|
65
|
|
|
438
|
|
|
384
|
|
|
54
|
|
||||||
Unrealized (gains) losses on commodity risk management activities
|
(8
|
)
|
|
(21
|
)
|
|
13
|
|
|
45
|
|
|
(6
|
)
|
|
51
|
|
||||||
Operating expenses, excluding non-cash compensation expense
|
(51
|
)
|
|
(46
|
)
|
|
(5
|
)
|
|
(90
|
)
|
|
(84
|
)
|
|
(6
|
)
|
||||||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(7
|
)
|
|
(5
|
)
|
|
(2
|
)
|
|
(13
|
)
|
|
(11
|
)
|
|
(2
|
)
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
|
7
|
|
|
18
|
|
|
(11
|
)
|
|
20
|
|
|
34
|
|
|
(14
|
)
|
||||||
Segment Adjusted EBITDA
|
$
|
208
|
|
|
$
|
148
|
|
|
$
|
60
|
|
|
$
|
400
|
|
|
$
|
317
|
|
|
$
|
83
|
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Transportation fees
|
$
|
134
|
|
|
$
|
104
|
|
|
$
|
30
|
|
|
$
|
251
|
|
|
$
|
228
|
|
|
$
|
23
|
|
Natural gas sales and other (excluding unrealized gains and losses)
|
108
|
|
|
61
|
|
|
47
|
|
|
199
|
|
|
94
|
|
|
105
|
|
||||||
Retained fuel revenues (excluding unrealized gains and losses)
|
13
|
|
|
15
|
|
|
(2
|
)
|
|
26
|
|
|
28
|
|
|
(2
|
)
|
||||||
Storage margin (excluding unrealized gains and losses)
|
4
|
|
|
1
|
|
|
3
|
|
|
7
|
|
|
28
|
|
|
(21
|
)
|
||||||
Unrealized gains (losses) on commodity risk management activities
|
8
|
|
|
21
|
|
|
(13
|
)
|
|
(45
|
)
|
|
6
|
|
|
(51
|
)
|
||||||
Total segment margin
|
$
|
267
|
|
|
$
|
202
|
|
|
$
|
65
|
|
|
$
|
438
|
|
|
$
|
384
|
|
|
$
|
54
|
|
•
|
an increase of
$47 million
in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity;
|
•
|
a net increase of
$5 million
due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of
$26 million
,
$6 million
and
$2 million
, respectively, and a decrease of
$13 million
in Adjusted EBITDA related to unconsolidated affiliates;
|
•
|
an increase of
$4 million
in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to higher demand on existing pipelines; and
|
•
|
an increase of
$3 million
in realized storage margin primarily due to higher realized derivative gains; partially offset by
|
•
|
a decrease of
$2 million
in retained fuel revenues as a result of lower natural gas pricing.
|
•
|
an increase of
$105 million
in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; and
|
•
|
a net increase of
$5 million
due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of
$26 million
,
$6 million
and
$2 million
, respectively, and a decrease of
$15 million
in Adjusted EBITDA related to unconsolidated affiliates;
partially offset by
|
•
|
a decrease of
$21 million
in realized storage margin primarily due to an adjustment to the Bammel storage inventory;
|
•
|
a decrease of
$3 million
in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to renegotiated contracts; and
|
•
|
a decrease of
$2 million
in retained fuel revenues due to lower natural gas pricing.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Natural gas transported (BBtu/d)
|
8,707
|
|
|
5,299
|
|
|
3,408
|
|
|
8,457
|
|
|
5,476
|
|
|
2,981
|
|
||||||
Natural gas sold (BBtu/d)
|
17
|
|
|
17
|
|
|
—
|
|
|
17
|
|
|
17
|
|
|
—
|
|
||||||
Revenues
|
$
|
328
|
|
|
$
|
207
|
|
|
$
|
121
|
|
|
$
|
644
|
|
|
$
|
442
|
|
|
$
|
202
|
|
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
|
(105
|
)
|
|
(67
|
)
|
|
(38
|
)
|
|
(199
|
)
|
|
(141
|
)
|
|
(58
|
)
|
||||||
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
|
(17
|
)
|
|
(7
|
)
|
|
(10
|
)
|
|
(34
|
)
|
|
(19
|
)
|
|
(15
|
)
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
|
123
|
|
|
128
|
|
|
(5
|
)
|
|
239
|
|
|
243
|
|
|
(4
|
)
|
||||||
Other
|
1
|
|
|
1
|
|
|
—
|
|
|
3
|
|
|
2
|
|
|
1
|
|
||||||
Segment Adjusted EBITDA
|
$
|
330
|
|
|
$
|
262
|
|
|
$
|
68
|
|
|
$
|
653
|
|
|
$
|
527
|
|
|
$
|
126
|
|
•
|
an increase of
$68 million
from the partial in service of the Rover pipeline with increases of
$105 million
in revenues,
$30 million
in operating expenses and
$7 million
in selling, general and administrative expenses; and
|
•
|
an aggregate increase of
$19 million
i
n revenues, excluding the incremental revenue related to the Rover pipeline in service discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by
$3 million
of lower revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by
|
•
|
an increase of
$8 million
in operating expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to higher maintenance project costs;
|
•
|
an increase of
$3 million
in selling, general and administrative expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to a reimbursement of legal fees and a franchise tax settlement received in 2017; and
|
•
|
a decrease of
$5 million
in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short-term firm capacity on Citrus.
|
•
|
An increase of
$117 million
from the partial in service of the Rover pipeline with increases of
$187 million
in revenues,
$56 million
in operating expenses and
$14 million
in selling, general and administrative expenses; and
|
•
|
an aggregate increase of
$21 million
in revenues, excluding the incremental revenues related to the Rover pipeline in service discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by
$6 million
of lower revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by
|
•
|
an increase of
$2 million
in operating expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to higher maintenance project costs; and
|
•
|
a decrease of
$4 million
in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short term firm capacity on Citrus.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Gathered volumes (BBtu/d)
|
11,576
|
|
|
10,961
|
|
|
615
|
|
|
11,442
|
|
|
10,599
|
|
|
843
|
|
||||||
NGLs produced (MBbls/d)
|
513
|
|
|
474
|
|
|
39
|
|
|
508
|
|
|
459
|
|
|
49
|
|
||||||
Equity NGLs (MBbls/d)
|
31
|
|
|
28
|
|
|
3
|
|
|
30
|
|
|
27
|
|
|
3
|
|
||||||
Revenues
|
$
|
1,874
|
|
|
$
|
1,615
|
|
|
$
|
259
|
|
|
$
|
3,488
|
|
|
$
|
3,252
|
|
|
$
|
236
|
|
Cost of products sold
|
1,281
|
|
|
1,044
|
|
|
237
|
|
|
2,342
|
|
|
2,168
|
|
|
174
|
|
||||||
Segment margin
|
593
|
|
|
571
|
|
|
22
|
|
|
1,146
|
|
|
1,084
|
|
|
62
|
|
||||||
Unrealized gains on commodity risk management activities
|
—
|
|
|
(3
|
)
|
|
3
|
|
|
—
|
|
|
(19
|
)
|
|
19
|
|
||||||
Operating expenses, excluding non-cash compensation expense
|
(169
|
)
|
|
(152
|
)
|
|
(17
|
)
|
|
(333
|
)
|
|
(313
|
)
|
|
(20
|
)
|
||||||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(20
|
)
|
|
(11
|
)
|
|
(9
|
)
|
|
(40
|
)
|
|
(34
|
)
|
|
(6
|
)
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
|
9
|
|
|
7
|
|
|
2
|
|
|
16
|
|
|
14
|
|
|
2
|
|
||||||
Other
|
1
|
|
|
—
|
|
|
1
|
|
|
2
|
|
|
—
|
|
|
2
|
|
||||||
Segment Adjusted EBITDA
|
$
|
414
|
|
|
$
|
412
|
|
|
$
|
2
|
|
|
$
|
791
|
|
|
$
|
732
|
|
|
$
|
59
|
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Gathering and processing fee-based revenues
|
$
|
453
|
|
|
$
|
436
|
|
|
$
|
17
|
|
|
$
|
874
|
|
|
$
|
844
|
|
|
$
|
30
|
|
Non-fee-based contracts and processing (excluding unrealized gains and losses)
|
140
|
|
|
132
|
|
|
8
|
|
|
272
|
|
|
221
|
|
|
51
|
|
||||||
Unrealized gains on commodity risk management activities
|
—
|
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
19
|
|
|
(19
|
)
|
||||||
Total segment margin
|
$
|
593
|
|
|
$
|
571
|
|
|
$
|
22
|
|
|
$
|
1,146
|
|
|
$
|
1,084
|
|
|
$
|
62
|
|
•
|
an increase of
$17 million
in fee-based margin due to growth in the Permian and Northeast regions, offset by declines in the South Texas, North Texas and midcontinent/Panhandle regions;
|
•
|
an increase of
$6 million
in non-fee-based margin primarily due to higher crude oil and NGL prices;
|
•
|
an increase of
$2 million
in non-fee-based margin due to increased throughput volume in the Permian region; and
|
•
|
an increase of
$2 million
in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by
|
•
|
an increase of
$17 million
in operating expenses primarily due to increases of
$6 million
in outside services,
$5 million
in materials,
$2 million
in employee costs and
$2 million
in ad valorem taxes; and
|
•
|
an increase of
$9 million
in selling, general and administrative expenses primarily due to a favorable impact recorded in the prior period from the adjustment of certain reserves in connection with contingent matters.
|
•
|
an increase of
$27 million
in non-fee-based margin primarily due to higher crude oil and NGL prices;
|
•
|
an increase of
$24 million
in non-fee-based margin due to increased throughput volume in the Permian region;
|
•
|
an increase of
$30 million
in fee-based margin due to growth in the Permian and Northeast regions, offset by declines in the South Texas, North Texas and midcontinent/Panhandle regions; and
|
•
|
an increase of
$2 million
in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by
|
•
|
an increase of
$20 million
in operating expenses due to increases of
$8 million
in outside services,
$5 million
in materials,
$4 million
in employee costs and
$3 million
in ad valorem taxes; and
|
•
|
an increase of
$6 million
in selling, general and administrative expenses primarily due to a favorable impact recorded in the prior period from the adjustment of certain reserves in connection with contingent matters.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
NGL transportation volumes (MBbls/d)
|
967
|
|
|
835
|
|
|
132
|
|
|
951
|
|
|
823
|
|
|
128
|
|
||||||
Refined products transportation volumes (MBbls/d)
|
637
|
|
|
643
|
|
|
(6
|
)
|
|
629
|
|
|
633
|
|
|
(4
|
)
|
||||||
NGL and refined products terminal volumes (MBbls/d)
|
789
|
|
|
767
|
|
|
22
|
|
|
746
|
|
|
779
|
|
|
(33
|
)
|
||||||
NGL fractionation volumes (MBbls/d)
|
473
|
|
|
431
|
|
|
42
|
|
|
473
|
|
|
430
|
|
|
43
|
|
||||||
Revenues
|
$
|
2,568
|
|
|
$
|
1,779
|
|
|
$
|
789
|
|
|
$
|
5,114
|
|
|
$
|
4,045
|
|
|
$
|
1,069
|
|
Cost of products sold
|
1,981
|
|
|
1,263
|
|
|
718
|
|
|
3,927
|
|
|
2,970
|
|
|
957
|
|
||||||
Segment margin
|
587
|
|
|
516
|
|
|
71
|
|
|
1,187
|
|
|
1,075
|
|
|
112
|
|
||||||
Unrealized (gains) losses on commodity risk management activities
|
13
|
|
|
(4
|
)
|
|
17
|
|
|
—
|
|
|
(54
|
)
|
|
54
|
|
||||||
Operating expenses, excluding non-cash compensation expense
|
(141
|
)
|
|
(125
|
)
|
|
(16
|
)
|
|
(280
|
)
|
|
(252
|
)
|
|
(28
|
)
|
||||||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(17
|
)
|
|
(17
|
)
|
|
—
|
|
|
(35
|
)
|
|
(36
|
)
|
|
1
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
|
19
|
|
|
18
|
|
|
1
|
|
|
40
|
|
|
35
|
|
|
5
|
|
||||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(1
|
)
|
||||||
Segment Adjusted EBITDA
|
$
|
461
|
|
|
$
|
388
|
|
|
$
|
73
|
|
|
$
|
912
|
|
|
$
|
769
|
|
|
$
|
143
|
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Fractionators and Refinery services margin
|
$
|
128
|
|
|
$
|
117
|
|
|
$
|
11
|
|
|
$
|
262
|
|
|
$
|
237
|
|
|
$
|
25
|
|
Transportation margin
|
290
|
|
|
241
|
|
|
49
|
|
|
556
|
|
|
474
|
|
|
82
|
|
||||||
Storage margin
|
48
|
|
|
53
|
|
|
(5
|
)
|
|
104
|
|
|
110
|
|
|
(6
|
)
|
||||||
Terminal Services margin
|
91
|
|
|
81
|
|
|
10
|
|
|
185
|
|
|
168
|
|
|
17
|
|
||||||
Marketing margin
|
43
|
|
|
20
|
|
|
23
|
|
|
80
|
|
|
32
|
|
|
48
|
|
||||||
Unrealized gains (losses) on commodity risk management activities
|
(13
|
)
|
|
4
|
|
|
(17
|
)
|
|
—
|
|
|
54
|
|
|
(54
|
)
|
||||||
Total segment margin
|
$
|
587
|
|
|
$
|
516
|
|
|
$
|
71
|
|
|
$
|
1,187
|
|
|
$
|
1,075
|
|
|
$
|
112
|
|
•
|
an increase of
$49 million
in transportation margin due to a
$43 million
increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines, an
$11 million
increase resulting from a reclassification between our transportation and fractionation margins, a
$4 million
increase due to higher throughput on Mariner West and a
$2 million
increase on Mariner South primarily due to system downtime in the prior period. These increases were partially offset by an
$11 million
decrease resulting from lower throughput on Mariner East 1 due to system downtime in the second quarter of 2018;
|
•
|
an increase of
$23 million
in marketing margin (excluding a net change of
$17 million
in unrealized gains and losses) due to gains of
$10 million
from our butane blending operations, a
$9 million
increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex and a
$4 million
increase from optimizing sales of purity product from our Mont Belvieu fractionators;
|
•
|
an increase of
$11 million
in fractionation and refinery services margin due to a
$14 million
increase resulting from higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility, a
$6 million
increase from blending gains as a result of improved market pricing and a
$2 million
increase from Mariner South as more cargoes were loaded at Mariner South. These increases were partially offset by an
$11 million
decrease resulting from a reclassification between our transportation and fractionation margins; and
|
•
|
an increase of
$10 million
in terminal services margin due to a
$7 million
increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018 and a
$5 million
increase at our Nederland terminal due to increased demand for propane exports. These increases were partially offset by a
$2 million
decrease due to the effect of Mariner East pipeline system downtime on our Marcus Hook Industrial Complex; partially offset by
|
•
|
an increase of
$16 million
in operating expenses primarily due to a
$7 million
increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, a
$4 million
increase in utilities and ad valorem taxes on the fractionators, and a
$3 million
increase in overhead costs; and
|
•
|
a decrease of
$5 million
in storage margin primarily due to the expiration and amendments to various NGL and refined products storage contracts.
|
•
|
an increase of
$82 million
in transportation margin due to
$78 million
from increased producer volumes from the Permian region on our Texas NGL pipelines, an
$11 million
increase due to higher throughput on Mariner West driven by end user facility constraints in the prior period, an
$11 million
increase resulting from a reclassification between our transportation and fractionation margins, a
$3 million
increase on Mariner South primarily due to system downtime in the prior period and a
$4 million
increase from higher deficiency fees. These increases were partially offset by a
$17 million
decrease resulting
|
•
|
an increase of
$48 million
in marketing margin (excluding a net change of
$54 million
in unrealized gains and losses) due to an
$18 million
increase from our butane blending operations, a
$17 million
increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex and a
$13 million
increase from optimizing sales of purity product from our Mont Belvieu fractionators;
|
•
|
an increase of
$25 million
in fractionation and refinery services margin due to a
$23 million
increase resulting from higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility, a
$9 million
increase from blending gains as a result of improved market pricing and a
$4 million
increase as we loaded more cargoes at our Mariner South export facility. These increases were partially offset by an
$11 million
decrease resulting from a reclassification between our transportation and fractionation margins;
|
•
|
an increase of
$17 million
in terminal services margin due to a
$18 million
increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018 and a
$6 million
increase at our Nederland terminal due to increased demand for propane exports. These increases were partially offset by a
$4 million
decrease due to the effect of Mariner East pipeline system downtime on our Marcus Hook Industrial Complex and a
$3 million
decrease from our marketing terminal volumes primarily due to the sale of one of our terminals in April 2017; and
|
•
|
an increase of
$5 million
in Adjusted EBITDA related to unconsolidated affiliates due to improved contributions from our unconsolidated refined products joint venture interests; partially offset by
|
•
|
an increase of
$28 million
in operating expenses due to a
$18 million
increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, a
$6 million
increases in certain allocated overhead and a
$4 million
increase in utilities and ad valorem taxes on the fractionators; and
|
•
|
a decrease of
$6 million
in storage margin due to a
$8 million
decrease from the expiration and amendments to various NGL and refined products storage contracts and a
$4 million
decrease from the expiration of a fixed fee transport agreement in 2017. These increases were partially offset by a
$6 million
increase from throughput fees collected at our Mont Belvieu storage terminal and increased demand on the Explorer Pipeline.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Crude transportation volumes (MBbls/d)
|
4,242
|
|
|
3,452
|
|
|
790
|
|
|
4,036
|
|
|
3,248
|
|
|
788
|
|
||||||
Crude terminals volumes (MBbls/d)
|
2,103
|
|
|
1,950
|
|
|
153
|
|
|
2,022
|
|
|
1,864
|
|
|
158
|
|
||||||
Revenues
|
$
|
4,803
|
|
|
$
|
2,465
|
|
|
$
|
2,338
|
|
|
$
|
8,548
|
|
|
$
|
5,040
|
|
|
$
|
3,508
|
|
Cost of products sold
|
4,361
|
|
|
2,091
|
|
|
2,270
|
|
|
7,538
|
|
|
4,394
|
|
|
3,144
|
|
||||||
Segment margin
|
442
|
|
|
374
|
|
|
68
|
|
|
1,010
|
|
|
646
|
|
|
364
|
|
||||||
Unrealized losses (gains) on commodity risk management activities
|
262
|
|
|
(2
|
)
|
|
264
|
|
|
305
|
|
|
(2
|
)
|
|
307
|
|
||||||
Operating expenses, excluding non-cash compensation expense
|
(144
|
)
|
|
(114
|
)
|
|
(30
|
)
|
|
(271
|
)
|
|
(186
|
)
|
|
(85
|
)
|
||||||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(20
|
)
|
|
(32
|
)
|
|
12
|
|
|
(42
|
)
|
|
(49
|
)
|
|
7
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
|
8
|
|
|
2
|
|
|
6
|
|
|
10
|
|
|
6
|
|
|
4
|
|
||||||
Segment Adjusted EBITDA
|
$
|
548
|
|
|
$
|
228
|
|
|
$
|
320
|
|
|
$
|
1,012
|
|
|
$
|
415
|
|
|
$
|
597
|
|
•
|
an increase of
$332 million
in segment margin (excluding unrealized losses on commodity risk management activities) due to a
$193 million
increase resulting primarily from placing our Bakken pipeline in service in the second quarter of 2017 as well as a
$27 million
increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets; a
$100 million
increase (excluding a net change of
$264 million
in unrealized gains and losses) from our crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets; and a
$9 million
increase in terminal fees primarily from ship loading fees at our Nederland facility as a result of increased exports;
|
•
|
a decrease of
$12 million
in selling, general and administrative expenses primarily due to higher professional fees recorded in the prior period; and
|
•
|
an increase of
$6 million
in Adjusted EBITDA related to unconsolidated affiliates due to a new contract at one of our joint ventures; partially offset by
|
•
|
an increase of
$30 million
in operating expenses due to a
$13 million
increase primarily resulting from placing our Bakken pipeline in service in the second quarter of 2017; a
$3 million
increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a
$14 million
increase from existing transportation assets due to increases of
$7 million
in utilities,
$5 million
in expense projects,
$5 million
in ad valorem taxes and
$5 million
in management fees, partially offset by decreases in environmental fees of
$5 million
and capacity leases of
$3 million
.
|
•
|
an increase of
$671 million
in segment margin (excluding unrealized losses on commodity risk management activities) due to a
$417 million
increase resulting primarily from placing our Bakken pipeline in service in the second quarter of 2017; a
$50 million
increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets; a
$188 million
increase (excluding a net change of
$307 million
in unrealized gains and losses) from our crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets; and a
$16 million
increase primarily from our Nederland facility due to higher ship loading fees as a result of increased exports;
|
•
|
a decrease of
$7 million
in selling, general and administrative expenses due to a
$13 million
decrease in professional fees, partially offset by an increase of
$6 million
related to Bakken insurance and management fees; and
|
•
|
an increase of
$4 million
in Adjusted EBITDA related to unconsolidated affiliates due to a new contract at one of our joint ventures; partially offset by
|
•
|
an increase of
$85 million
in operating expenses due to a
$39 million
increase primarily resulting from placing our Bakken pipeline in service in the second quarter of 2017; a
$15 million
increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a
$31 million
increase from existing transportation assets due to increases of
$10 million
in ad valorem taxes,
$9 million
in management fees,
$8 million
in utilities,
$5 million
in expense projects and
$5 million
in freight, partially offset by decreases in environmental fees of
$5 million
and capacity leases of
$1 million
.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Revenues
|
$
|
502
|
|
|
$
|
870
|
|
|
$
|
(368
|
)
|
|
$
|
1,073
|
|
|
$
|
1,640
|
|
|
$
|
(567
|
)
|
Cost of products sold
|
445
|
|
|
794
|
|
|
(349
|
)
|
|
921
|
|
|
1,462
|
|
|
(541
|
)
|
||||||
Segment margin
|
57
|
|
|
76
|
|
|
(19
|
)
|
|
152
|
|
|
178
|
|
|
(26
|
)
|
||||||
Unrealized (gains) losses on commodity risk management activities
|
(2
|
)
|
|
(4
|
)
|
|
2
|
|
|
2
|
|
|
(17
|
)
|
|
19
|
|
||||||
Operating expenses, excluding non-cash compensation expense
|
(10
|
)
|
|
(31
|
)
|
|
21
|
|
|
(41
|
)
|
|
(52
|
)
|
|
11
|
|
||||||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(19
|
)
|
|
(27
|
)
|
|
8
|
|
|
(37
|
)
|
|
(48
|
)
|
|
11
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
|
62
|
|
|
76
|
|
|
(14
|
)
|
|
88
|
|
|
156
|
|
|
(68
|
)
|
||||||
Other and eliminations
|
2
|
|
|
17
|
|
|
(15
|
)
|
|
—
|
|
|
13
|
|
|
(13
|
)
|
||||||
Segment Adjusted EBITDA
|
$
|
90
|
|
|
$
|
107
|
|
|
$
|
(17
|
)
|
|
$
|
164
|
|
|
$
|
230
|
|
|
$
|
(66
|
)
|
•
|
our equity method investment in limited partnership units of Sunoco LP consisting of
26.2 million
and
43.5 million
Sunoco LP common units, representing
31.8%
and
43.7%
of Sunoco LP’s total outstanding common units as of
June 30, 2018
and
June 30, 2017
,
respectively.
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased
17,286,859
Sunoco LP common units owned by ETP for aggregate cash consideration of approximately
$540 million
;
|
•
|
our natural gas marketing and compression operations. Subsequent to our contribution of CDM to USAC in April 2018, our all other segment includes our equity method investment in USAC consisting of
19.2 million
USAC common units and
6.4 million
USAC Class B Units, together representing
26.6%
of the limited partner interests
;
|
•
|
a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and
|
•
|
our investment in coal handling facilities.
|
•
|
a decrease of
$44 million
in Adjusted EBITDA related to unconsolidated affiliates from our investment in Sunoco LP resulting from the Partnership’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018; and
|
•
|
a decrease of
$12 million
due to the contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by
|
•
|
a decrease of
$14 million
in merger and acquisition expenses related to the Sunoco Logistics merger in 2017, partially offset by the CDM Contribution in 2018;
|
•
|
an increase of
$12 million
in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES;
|
•
|
an increase of
$6 million
from gains in power trading activities; and
|
•
|
an increase of
$2 million
in margin due to the expiration of a capacity contract commitment.
|
•
|
a decrease of
$69 million
in Adjusted EBITDA related to unconsolidated affiliates from our investment in Sunoco LP resulting from the Partnership’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018;
|
•
|
a decrease of
$18 million
in Adjusted EBITDA related to unconsolidated affiliates primarily from our investment in PES; and
|
•
|
a decrease of
$9 million
due to the contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by
|
•
|
a decrease of
$17 million
in merger and acquisition expenses related to the Sunoco Logistics merger in 2017, partially offset by the CDM Contribution in 2018;
|
•
|
an increase of
$8 million
from commodity trading activities; and
|
•
|
an increase of
$5 million
in margin from the expiration of a capacity contract commitment.
|
|
Growth
|
|
Maintenance
|
||||||||||||
|
Low
|
|
High
|
|
Low
|
|
High
|
||||||||
Intrastate transportation and storage
|
$
|
275
|
|
|
$
|
300
|
|
|
$
|
30
|
|
|
$
|
35
|
|
Interstate transportation and storage
(1)
|
500
|
|
|
550
|
|
|
115
|
|
|
120
|
|
||||
Midstream
|
850
|
|
|
875
|
|
|
120
|
|
|
130
|
|
||||
NGL and refined products transportation and services
|
2,350
|
|
|
2,500
|
|
|
60
|
|
|
70
|
|
||||
Crude oil transportation and services
(1)
|
450
|
|
|
475
|
|
|
90
|
|
|
100
|
|
||||
All other (including eliminations)
|
75
|
|
|
100
|
|
|
60
|
|
|
65
|
|
||||
Total capital expenditures
|
$
|
4,500
|
|
|
$
|
4,800
|
|
|
$
|
475
|
|
|
$
|
520
|
|
(1)
|
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
|
||||||
Intrastate transportation and storage
|
$
|
195
|
|
|
$
|
21
|
|
|
$
|
216
|
|
Interstate transportation and storage
|
351
|
|
|
37
|
|
|
388
|
|
|||
Midstream
|
448
|
|
|
65
|
|
|
513
|
|
|||
NGL and refined products transportation and services
|
974
|
|
|
26
|
|
|
1,000
|
|
|||
Crude oil transportation and services
|
205
|
|
|
21
|
|
|
226
|
|
|||
All other (including eliminations)
|
68
|
|
|
34
|
|
|
102
|
|
|||
Total capital expenditures
|
$
|
2,241
|
|
|
$
|
204
|
|
|
$
|
2,445
|
|
•
|
$1.00 billion
aggregate principal amount of
4.875%
senior notes due 2023;
|
•
|
$800 million
aggregate principal amount of
5.50%
senior notes due 2026; and
|
•
|
$400 million
aggregate principal amount of
5.875%
senior notes due 2028.
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
ETP Senior Notes
(1)(2)
|
$
|
29,354
|
|
|
$
|
27,005
|
|
Transwestern Senior Notes
|
575
|
|
|
575
|
|
||
Panhandle Senior Notes
|
386
|
|
|
785
|
|
||
Credit facilities and commercial paper:
|
|
|
|
||||
ETP $4.00 billion Revolving Credit Facility due December 2022
(3)
|
1,228
|
|
|
2,292
|
|
||
ETP $1.00 billion 364-Day Credit Facility due November 2018
|
—
|
|
|
50
|
|
||
Bakken Project $2.50 billion Credit Facility due August 2019
|
2,500
|
|
|
2,500
|
|
||
Other long-term debt
|
4
|
|
|
5
|
|
||
Unamortized premiums, net of discounts and fair value adjustments
|
39
|
|
|
61
|
|
||
Deferred debt issuance costs
|
(190
|
)
|
|
(179
|
)
|
||
Total debt
|
33,896
|
|
|
33,094
|
|
||
Less: current maturities of long-term debt
|
155
|
|
|
407
|
|
||
Long-term debt, less current maturities
|
$
|
33,741
|
|
|
$
|
32,687
|
|
(1)
|
Includes
$600 million
aggregate principal amount of
6.70%
senior notes due July 1, 2018 that were classified as long-term as of
June 30, 2018
as they were refinanced on a long-term basis in June 2018, see “ETP Senior Notes Offering and Redemption” below.
|
(2)
|
Includes
$400 million
aggregate principal amount of
9.70%
senior notes due March 15, 2019 and
$450 million
aggregate principal amount of
9.00%
senior notes due April 15, 2019 that were classified as long-term as of
June 30, 2018
as management has the intent and ability to refinance the borrowings on a long-term basis.
|
(3)
|
Includes
$1.23 billion
and
$2.01 billion
of commercial paper outstanding at
June 30, 2018
and
December 31, 2017
, respectively.
|
•
|
$500 million
aggregate principal amount of
4.20%
senior notes due 2023
;
|
•
|
$1.00 billion
aggregate principal amount of
4.95%
senior notes due 2028
;
|
•
|
$500 million
aggregate principal amount of
5.80%
senior notes due 2038
; and
|
•
|
$1.00 billion
aggregate principal amount of
6.00%
senior notes due 2048.
|
•
|
ETP’s
$650 million
aggregate principal amount of
2.50%
senior notes due June 15, 2018;
|
•
|
Panhandle’s
$400 million
aggregate principal amount of
7.00%
senior notes due June 15, 2018; and
|
•
|
ETP’s
$600 million
aggregate principal amount of
6.70%
senior notes due July 1, 2018.
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2017
|
|
February 8, 2018
|
|
February 14, 2018
|
|
$
|
0.5650
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 15, 2018
|
|
0.5650
|
|
|
June 30, 2018
|
|
August 6, 2018
|
|
August 14, 2018
|
|
0.5650
|
|
Period Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
Series A Preferred Units
|
|
|
|
|
|
|
||
December 31, 2017
|
|
February 1, 2018
|
|
February 15, 2018
|
|
$
|
15.451
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
31.250
|
|
|
Series B Preferred Units
|
|
|
|
|
|
|
||
December 31, 2017
|
|
February 1, 2018
|
|
February 15, 2018
|
|
$
|
16.378
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
33.125
|
|
|
Series C Preferred Units
|
|
|
|
|
|
|
||
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
$
|
0.56337
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Limited Partners:
|
|
|
|
||||
Common Units held by public
|
$
|
1,286
|
|
|
$
|
1,156
|
|
Common Units held by ETE
|
31
|
|
|
30
|
|
||
General Partner interest and incentive distributions held by ETE
|
900
|
|
|
781
|
|
||
IDR relinquishments
|
(84
|
)
|
|
(319
|
)
|
||
Series A Preferred Units
|
30
|
|
|
—
|
|
||
Series B Preferred Units
|
18
|
|
|
—
|
|
||
Series C Preferred Units
|
10
|
|
|
—
|
|
||
Total distributions declared to partners
|
$
|
2,191
|
|
|
$
|
1,648
|
|
|
|
Year Ending December 31,
|
||
2018 (remainder)
|
|
$
|
69
|
|
2019
|
|
128
|
|
|
Each year beyond 2019
|
|
33
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||||||||||||||||
|
Notional Volume
|
|
Fair Value Asset (Liability)
|
|
Effect of Hypothetical 10% Change
|
|
Notional Volume
|
|
Fair Value Asset (Liability)
|
|
Effect of Hypothetical 10% Change
|
||||||||||
Mark-to-Market Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Swaps/Futures
|
465
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
1,078
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Basis Swaps IFERC/NYMEX
(1)
|
102,328
|
|
|
3
|
|
|
—
|
|
|
48,510
|
|
|
2
|
|
|
1
|
|
||||
Options – Puts
|
(3,043
|
)
|
|
—
|
|
|
—
|
|
|
13,000
|
|
|
—
|
|
|
—
|
|
||||
Power (Megawatt):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Forwards
|
3,196,100
|
|
|
12
|
|
|
8
|
|
|
435,960
|
|
|
1
|
|
|
1
|
|
||||
Futures
|
(42,768
|
)
|
|
—
|
|
|
—
|
|
|
(25,760
|
)
|
|
—
|
|
|
—
|
|
||||
Options – Puts
|
(30,532
|
)
|
|
1
|
|
|
—
|
|
|
(153,600
|
)
|
|
—
|
|
|
1
|
|
||||
Options – Calls
|
996,172
|
|
|
—
|
|
|
1
|
|
|
137,600
|
|
|
—
|
|
|
—
|
|
||||
Crude (MBbls) – Futures
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
(Non-Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basis Swaps IFERC/NYMEX
|
6,600
|
|
|
(50
|
)
|
|
18
|
|
|
4,650
|
|
|
(13
|
)
|
|
4
|
|
||||
Swing Swaps IFERC
|
52,413
|
|
|
(1
|
)
|
|
—
|
|
|
87,253
|
|
|
(2
|
)
|
|
1
|
|
||||
Fixed Swaps/Futures
|
5,360
|
|
|
(2
|
)
|
|
3
|
|
|
(4,700
|
)
|
|
(1
|
)
|
|
2
|
|
||||
Forward Physical Contracts
|
(174,465
|
)
|
|
4
|
|
|
—
|
|
|
(145,105
|
)
|
|
6
|
|
|
41
|
|
||||
NGL (MBbls) – Forwards/Swaps
|
(1,590
|
)
|
|
(16
|
)
|
|
11
|
|
|
(2,493
|
)
|
|
5
|
|
|
16
|
|
||||
Crude (MBbls) – Forwards/Swaps
|
44,190
|
|
|
(307
|
)
|
|
261
|
|
|
9,172
|
|
|
(4
|
)
|
|
9
|
|
||||
Refined Products (MBbls) – Futures
|
(1,076
|
)
|
|
(5
|
)
|
|
5
|
|
|
(3,783
|
)
|
|
(25
|
)
|
|
4
|
|
||||
Fair Value Hedging Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Non-Trading)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basis Swaps IFERC/NYMEX
|
(21,475
|
)
|
|
(1
|
)
|
|
—
|
|
|
(39,770
|
)
|
|
(2
|
)
|
|
—
|
|
||||
Fixed Swaps/Futures
|
(21,475
|
)
|
|
(1
|
)
|
|
7
|
|
|
(39,770
|
)
|
|
14
|
|
|
11
|
|
(1)
|
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
|
Term
|
|
Type
(1)
|
|
Notional Amount Outstanding
|
||||||
June 30, 2018
|
|
December 31, 2017
|
||||||||
July 2018
(2)
|
|
Forward-starting to pay a fixed rate of 3.76% and receive a floating rate
|
|
$
|
—
|
|
|
$
|
300
|
|
July 2019
(2)
|
|
Forward-starting to pay a fixed rate of 3.56% and receive a floating rate
|
|
400
|
|
|
300
|
|
||
July 2020
(2)
|
|
Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
|
|
400
|
|
|
400
|
|
||
July 2021
(2)
|
|
Forward-starting to pay a fixed rate of 3.55% and receive a floating rate
|
|
400
|
|
|
—
|
|
||
December 2018
|
|
Pay a floating rate 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 30 years with a mandatory termination date the same as the effective date.
|
•
|
changes in ETE’s and ETP’s business, operations and prospects;
|
•
|
changes in market assessments of ETE’s and ETP’s business, operations and prospects;
|
•
|
interest rates, general market, industry and economic conditions and other factors generally affecting the price of ETE common units; and
|
•
|
federal, state and local legislation, governmental regulation and legal developments in the businesses in which ETE and ETP operate.
|
•
|
any resolution or course of action by ETP GP or its affiliates in respect of a conflict of interest is permitted and deemed approved by all partners of ETP (i.e. the ETP unitholders), and will not constitute a breach of the ETP partnership agreement or of any duty stated or implied by law or equity, if the resolution or course of action is approved by Special Approval or unaffiliated ETP unitholder approval; and
|
•
|
ETP GP may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants selected by it, and any act taken or omitted to be taken in reliance upon the opinion of such persons as to matters that ETP GP reasonably believes to be within such person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.
|
•
|
the parties may be liable for damages to one another under the terms and conditions of the merger agreement;
|
•
|
negative reactions from the financial markets, including declines in the price of ETE common units or ETP common units due to the fact that current prices may reflect a market assumption that the merger will be completed;
|
•
|
having to pay certain significant costs relating to the merger, including, in certain circumstances, the reimbursement by ETP of up to $30 million of ETE’s expenses and a termination fee of $750 million less any previous expense reimbursements by ETP; and
|
•
|
the attention of management of ETE and ETP will have been diverted to the merger rather than other strategic opportunities that could have been beneficial to that organization.
|
Exhibit Number
|
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Description
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101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document
|
101.CAL*
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|
XBRL Taxonomy Extension Calculation Linkbase Document
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101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
101.LAB*
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
*
|
|
Filed herewith.
|
**
|
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Furnished herewith.
|
***
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Denotes a management contract or compensatory plan or arrangement. Filed herewith.
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|
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ENERGY TRANSFER PARTNERS, L.P.
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By:
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Energy Transfer Partners GP, L.P.
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its General Partner
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By:
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Energy Transfer Partners, L.L.C.
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its General Partner
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Date:
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August 9, 2018
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By:
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/s/ A. Troy Sturrock
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A. Troy Sturrock
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Senior Vice President, Controller and Principal Accounting Officer
(duly authorized to sign on behalf of the registrant)
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AMENDED AND RESTATED
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ENERGY TRANSFER PARTNERS, L.L.C.
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ANNUAL BONUS PLAN
|
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1.
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Purpose.
The purpose of this Plan is to motivate management and the employees who perform services for the Partnership and/or its affiliates and subsidiaries to earn annual cash awards through the achievement of performance and target goals.
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2.
|
Definitions.
As used in this Plan, the following terms shall have the meanings herein specified:
|
2.1
|
Actual Results
means the dollar amount of Adjusted EBITDA, Distributable Cash Flow, Departmental Budget or other applicable financial measure specified for the Budget Target(s) for a Plan Year actually achieved for such Plan Year as determined by the Partnership following the end of such Plan Year.
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2.2
|
Adjusted EBITDA
means earnings before interest, taxes, depreciation and amortization adjusted for non-cash compensation and extraordinary costs, including but not limited to transactional costs.
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2.3
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Annual Bonus
means the cash bonus paid to an Eligible Employee for the Plan Year.
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2.4
|
Annual Target Bonus
means, for an Eligible Employee, a percentage of such Eligible Employee’s Eligible Earnings, and shall be dependent on a number of factors which may include but are not limited to an employee’s position title, job responsibilities, and reporting level within the Company. The Company may, but is not required to, specify a specific range for an Eligible Employee at any time prior to or during a Plan Year; provided that any such range may be adjusted from time to time or at any time in the Company’s sole discretion, including for the applicable Plan Year.
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2.5
|
Annual Target Bonus Pool
means, for a Plan Year, the Target Bonus of the Eligible Employees of the Company for that Plan Year.
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2.6
|
Board
means the Board of Directors of the Company.
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2.7
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Bonus Pool Payout Factor
means the multiplier factor applied to the Annual Target Bonus Pool to determine the Funded Bonus Pool for the applicable Plan Year. The payout is determined by the comparison of the Budget Target(s) for the Plan Year to Actual Results. General guidelines for the Budget Target and the Bonus Pool Payout Factor associated with such Budget Target for a Plan Year are set forth below, but each are subject to the sole discretion of the Compensation Committee. The Bonus Pool Payout Factor for purposes of the Plan shall be adjusted each Plan Year based on the specific allocation of Annual Target Bonus Pools to each of the specified Budget Target(s). Such allocations of each Budget Target to the total Annual Bonus Pool shall be determined on an annual basis by the Compensation Committee. For 2018, the Adjusted EBITDA Budget Target shall comprise 60% of the total Annual Target Bonus Pool, the Distributable Cash Flow Budget Target shall comprise 20% of the total Annual Target Bonus Pool and the Departmental Budget Target shall comprise the remaining 20% of the total Annual Target Bonus Pool. While the Funded Bonus Pool will reflect an aggregation of performance under each Bonus Pool Payout Factor the performance of Adjusted EBITDA Budget Target shall drive calculation of the Bonus Pool, as no other targets shall be considered unless the Adjusted EBITDA Target results is at least 80% of its Budget Target.
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% of Budget Target
|
Bonus Pool Payout Factor
|
>=110.0
|
1.20x
|
109.9 – 105.0
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1.10x
|
104.9 – 95.0
|
1.00x
|
94.9 – 90.0
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.90x
|
89.9 – 80.0
|
.75x
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< 80.0
|
.0x
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% of Budget Target
|
Bonus Pool Payout Factor
|
>=110.0
|
1.20x
|
109.9 – 105.0
|
1.10x
|
104.9 – 95.0
|
1.00x
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94.9 – 90.0
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.90x
|
89.9 – 80.0
|
.75x
|
< 80.0
|
.0x
|
% of Budget Target
|
Bonus Pool Payout Factor
|
0.0-100.9
|
1.00x
|
101.0-105.9
|
.90x
|
106.0 – 110.9
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.70x
|
111.0-114.9
|
.50x
|
>115
|
.0x
|
2.8
|
Budget Target
means the specific dollar amount of Adjusted EBITDA, Distributable Cash Flow, total Departmental Budget and/or other financial measure(s) established by the Compensation Committee for the Company for a Plan Year.
|
2.9
|
Company
means Energy Transfer Partners, L.L.C., a Delaware limited liability company. The term “Company” shall include any successor to Energy Transfer
|
2.10
|
Compensation Committee
means the Compensation Committee of the Company’s Board.
|
2.11
|
Departmental Budget
means the specific dollar amount of general and administrative expenses (i.e. operating budget) or operating and maintenance expenses set for each department of Partnership and its subsidiaries. In the case where a department head oversees multiple departments the Departmental Budget shall be the total aggregate budget for all of his/her departments.
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2.12
|
Distributable Cash Flow
means net income, adjusted for certain non-cash items, less maintenance capital expenditures.
|
2.13
|
Eligible Earnings
means the aggregate regular earnings plus overtime earnings, if any, received by an Eligible Employee during the Plan Year. For the avoidance of doubt, neither distribution payments or distribution equivalent payments on any Partnership restricted or common units nor any other bonus or sign-on payments received by an Eligible Employee during the Plan Year shall be included in the calculation of Eligible Earnings for an Eligible Employee.
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2.14
|
Eligible Employee
has the meaning set forth in Section 4 below.
|
2.15
|
Funded Bonus Pool
means the Annual Target Bonus Pool for a Plan Year multiplied by the applicable Bonus Pool Payout Factor for such Plan Year. The establishment and amount of a Funded Bonus Pool is 100% discretionary and subject to the final approval of and/or adjustment by the Compensation Committee.
|
2.16
|
Operational Safety Standards
means the safety standards, training and requirements set forth on Exhibit A hereto, which operations based Eligible Employees are required to comply.
|
2.17
|
Partnership
means Energy Transfer Partners L.P., a Delaware master limited partnership.
|
2.18
|
Person
means an individual, corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.
|
2.19
|
Plan
means the Company’s Annual Bonus Plan as set forth herein, as the same may be amended from time to time.
|
2.20
|
Plan Year
means the performance (calendar) year for the measurement and determination of the Budget Target and the calculation of Actual Results. Unless otherwise determined by the Compensation Committee, each Plan Year shall be the one year period commencing on January 1 and ending on December 31 of the calendar year.
|
3.
|
Plan Guidelines and Administration.
The administration of the Plan and any potential Annual Bonus awarded pursuant to the Plan are subject to the sole determination and discretion of the Compensation Committee. The Compensation Committee will review the Partnership’s performance results for the designated Plan Year, the Budget Target and Bonus Pool Payout
|
4.
|
Eligible Employees.
Subject to the discretion of the Compensation Committee and such other criteria as may be established by the Compensation Committee in general or for a particular Plan Year, all regular full-time employees providing services to the Partnership and its subsidiaries are eligible to participate in the Annual Target Bonus Pool for a Plan Year. No Eligible Employee shall be entitled to receive an Annual Bonus for a Plan Year unless he or she is actively employed by the Company (or one of its Affiliates) on the date the Annual Bonus for such Plan Year is paid by the Company even if such payment date is after the Plan Year.
|
5.
|
Annual Bonus Payments for Eligible Employees
. As soon as reasonably practicable following the end of the Plan Year, management of the Company will determine the Annual Target Bonus for each Eligible Employee. The Funded Bonus Pool from which Annual Bonuses are paid to Eligible Employees shall equal (a) the aggregate of the Annual Target Bonuses of all Eligible Employees multiplied by (b) the Bonus Pool Payout Factor for such Plan Year, as determined by the Compensation Committee after review of the performance results for the Plan year. The amount of the Annual Bonus for an Eligible Employee from the Funded Bonus Pool shall be determined in management’s sole discretion and shall be based on a number of factors including an employee’s performance, length of employment and such other factors as may be determined by management in its sole discretion, which factors may not be the same fall all Eligible Employees. Notwithstanding the foregoing, the Compensation Committee shall make determination of the Annual Bonus of all of the Company’s named executive officers and such other executive officers as may be determined from time to time.
|
6.
|
Amendment and Termination.
The Compensation Committee, at its sole discretion, may, without prior notice to or consent of any Eligible Employees, amend the Plan or terminate the Plan at any time and at all times.
|
7.
|
Indemnification.
Neither the Company, any participating Affiliate, nor the Board, or the Compensation Committee, of the Company or any participating affiliate, nor any officer or employee of the Company or any participating affiliate shall be liable for any act, omission, interpretation, construction or determination made in connection with the Plan in good faith; and the members of the Company’s Board, the Compensation Committee and/or management of the Company shall be entitled to indemnification and reimbursement by the Company to the maximum extent permitted by law in respect of any claim, loss, damage or expense (including counsel’s fees) arising from their acts, omission and conduct in their official capacity with respect to the Plan.
|
8.
|
General provisions.
|
8.1
|
Non-Guarantee of Employment or Participation in the Plan
. Nothing contained in this Plan shall be construed as a contract of employment between the Company, the Partnership and/or any of its affiliates and any employee of the Company or any of its affiliates, and nothing in this Plan shall confer upon any employee, including an Eligible Employee, any right to continued employment with the Company and/or its affiliate, or interfere with the right of the Company, the Partnership and/or its affiliate to terminate the employment, with or without cause, of an employee, including an Eligible Employee. Nothing in this Plan shall give any employee any right to participate in the Plan and/or to receive an Annual Bonus with respect to any Plan Year.
|
8.2
|
Interests Not Transferable
. No right, interest or benefit under the Plan shall be subject in any manner to alienation, sale, transfer, assignment, pledge, attachment or other legal process, or encumbrance of any kind, and any attempt to do so shall be void.
|
8.3
|
Controlling Law
. To the extent not superseded by federal law, the law of the State of Texas, without regard to the conflicts of laws provisions thereunder, shall be controlling in all matters relating to the Plan.
|
8.4
|
Severability
. If any Plan provision or any Annual Bonus award hereunder is or becomes or is deemed to be invalid, illegal, or unenforceable in any jurisdiction or as to any person or award, or would disqualify the Plan or any award under the law deemed applicable by the Compensation Committee, such provision shall be construed or deemed amended to conform to the applicable laws, or if it cannot be construed or deemed amended without, in the determination of the Compensation Committee, materially altering the intent of the Plan or the award, such provision shall be stricken as to such jurisdiction, person or award and the remainder of the Plan and any such award shall remain in full force and effect.
|
8.5
|
No Trust or Fund Created
. Neither the Plan nor any award shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Company and its Affiliates and an employee, including an Eligible Employee or any other person. The Plan shall constitute an unfunded mechanism for the Company to pay bonus compensation to participants from its general assets.
No participant shall have any security or other interest in the assets of the Company.
|
8.6
|
Headings
. Headings are given to the sections of the Plan solely as a convenience to facilitate reference. Such headings shall not be deemed in any way material or relevant to the construction or interpretation of the Plan or any provision of it.
|
8.7
|
Tax Withholding
. The Company and/or any participating Affiliate may deduct from any payment otherwise due under this Plan to a Participant (or beneficiary) amounts required by law to be withheld for purposes of federal, state or local taxes.
|
8.8
|
Off-set.
The Company reserves the right to withhold any or all portions of an award or to reduce an award to a participant up to an amount equal to any amount the participant owes to the Company or any of its Affiliates.
|
8.9
|
Effective Date.
This Plan was effective for the Plan Year commencing on January 1, 2014 and was amended and restated effective for the Plan year commencing on January 1, 2018.
|
1.
|
Satisfactory completion of all required safety training and instruction
|
2.
|
Attendance at all required safety meetings
|
3.
|
Avoidance of preventable vehicle incidents
|
4.
|
Management discretion of overall compliance and understanding of safety standards and requirements for operation
|
|
Six Months Ended June 30, 2018
|
||||||
|
Energy Transfer Partners, L.P. (consolidated)
|
|
Sunoco Logistics Partners Operations L.P.
|
||||
Fixed Charges:
|
|
|
|
||||
Interest expense, net
|
$
|
704
|
|
|
$
|
81
|
|
Capitalized interest
|
160
|
|
|
106
|
|
||
Interest charges included in rental expense
|
4
|
|
|
2
|
|
||
Total fixed charges
|
868
|
|
|
189
|
|
||
Series A, B and C preferred unit distributions
|
54
|
|
|
—
|
|
||
Total fixed charges and preferred unit distributions
|
922
|
|
|
189
|
|
||
|
|
|
|
||||
Earnings:
|
|
|
|
||||
Income before income tax expense
|
1,510
|
|
|
278
|
|
||
Less: equity in earnings of unconsolidated affiliates
|
34
|
|
|
91
|
|
||
Total earnings
|
1,476
|
|
|
187
|
|
||
Add:
|
|
|
|
||||
Fixed charges
|
868
|
|
|
189
|
|
||
Amortization of capitalized interest
|
11
|
|
|
2
|
|
||
Distributed income of equity investees
|
215
|
|
|
79
|
|
||
Less:
|
|
|
|
||||
Interest capitalized
|
(160
|
)
|
|
(106
|
)
|
||
Income available for fixed charges
|
$
|
2,410
|
|
|
$
|
351
|
|
|
|
|
|
||||
Ratio of earnings to fixed charges
|
2.78
|
|
|
1.86
|
|
||
|
|
|
|
||||
Ratio of earnings to fixed charges and preferred unit distributions
|
2.61
|
|
|
1.86
|
|
1.
|
I have reviewed this quarterly report on Form 10-Q of Energy Transfer Partners, L.P.;
|
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(s) 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(s) 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 quarterly report on Form 10-Q of Energy Transfer Partners, L.P.;
|
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(s) 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(s) 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, as amended; 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, as amended; 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
|