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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Energy Transfer Equity, L.P. Energy Transfer Equity, L.P. Common Units Representing Limited Partnership Interests (delisted) | NYSE:ETE | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 16.82 | 0 | 01:00:00 |
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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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30-0108820
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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 content
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CDM
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CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively
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DOJ
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U.S. Department of Justice
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EPA
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Environmental Protection Agency
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ETP
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Energy Transfer Partners, L.P.
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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 Series A Preferred Units
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ETP’s 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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ETP Series B Preferred Units
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ETP’s 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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ETP Series C Preferred Units
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ETP’s 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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ETP Series D Preferred Units
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ETP’s 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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EPA
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U.S. Environmental Protection Agency
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Exchange Act
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Securities Exchange Act of 1934
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FERC
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Federal Energy Regulatory Commission
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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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Lake Charles LNG
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Lake Charles LNG Company, LLC
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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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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
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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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RIGS
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Regency Interstate Gas LP
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Rover
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Rover Pipeline LLC
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SEC
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Securities and Exchange Commission
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Series A Convertible Preferred Units
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ETE Series A convertible preferred units
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Sunoco Logistics
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Sunoco Logistics Partners L.P.
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Sunoco LP
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Sunoco LP (previously named Susser Petroleum Partners, LP)
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Sunoco LP Series A Preferred Units
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Sunoco LP Series A Preferred Units previously held by ETE
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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
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USAC
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USA Compression Partners, LP
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USAC Preferred Units
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USAC Series A Preferred Units
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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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519
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$
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336
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Accounts receivable, net
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4,309
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4,504
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Accounts receivable from related companies
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106
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53
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Inventories
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1,802
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2,022
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Derivative assets
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63
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24
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Income taxes receivable
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172
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136
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Other current assets
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616
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295
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Current assets held for sale
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6
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3,313
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Total current assets
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7,593
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10,683
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Property, plant and equipment
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76,409
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71,177
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Accumulated depreciation and depletion
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(11,529
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)
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(10,089
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)
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64,880
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61,088
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||||
Advances to and investments in unconsolidated affiliates
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2,687
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2,705
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Other non-current assets, net
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996
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886
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Intangible assets, net
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6,088
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6,116
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Goodwill
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5,173
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4,768
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Total assets
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$
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87,417
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$
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86,246
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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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3,955
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$
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4,685
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Accounts payable to related companies
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102
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31
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Derivative liabilities
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392
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111
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Income taxes payable
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195
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—
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Accrued and other current liabilities
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2,832
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2,582
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Current maturities of long-term debt
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160
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413
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Current liabilities held for sale
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—
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75
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Total current liabilities
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7,636
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7,897
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Long-term debt, less current maturities
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44,473
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43,671
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Non-current derivative liabilities
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136
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145
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Deferred income taxes
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3,075
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3,315
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Other non-current liabilities
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1,227
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1,217
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||||
Commitments and contingencies
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|
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||||
Redeemable noncontrolling interests
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487
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21
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||||
Equity:
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|
||||
Limited Partners:
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|
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|
||||
Series A Convertible Preferred Units
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—
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|
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450
|
|
||
Common Unitholders
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(1,106
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)
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(1,643
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)
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General Partner
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(4
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)
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(3
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)
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||
Total partners’ deficit
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(1,110
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)
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(1,196
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)
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||
Noncontrolling interest
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31,493
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31,176
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||
Total equity
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30,383
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|
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29,980
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||
Total liabilities and equity
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$
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87,417
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$
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86,246
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|
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Three Months Ended
June 30, |
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Six Months Ended
June 30, |
||||||||||||
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2018
|
|
2017*
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2018
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2017*
|
||||||||
REVENUES:
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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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$
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2,086
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$
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2,034
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NGL sales
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2,141
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1,487
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4,171
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3,033
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||||
Crude sales
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4,241
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2,345
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7,495
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|
4,887
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|
||||
Gathering, transportation and other fees
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1,667
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1,111
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3,097
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2,176
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|
||||
Refined product sales
|
4,818
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|
2,903
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8,628
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|
5,918
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|
||||
Other
|
227
|
|
|
559
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|
|
523
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|
1,040
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|
||||
Total revenues
|
14,118
|
|
|
9,427
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|
|
26,000
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|
|
19,088
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|
||||
COSTS AND EXPENSES:
|
|
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|
||||||||
Cost of products sold
|
11,343
|
|
|
7,167
|
|
|
20,588
|
|
|
14,677
|
|
||||
Operating expenses
|
772
|
|
|
648
|
|
|
1,496
|
|
|
1,249
|
|
||||
Depreciation, depletion and amortization
|
694
|
|
|
607
|
|
|
1,359
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|
|
1,235
|
|
||||
Selling, general and administrative
|
183
|
|
|
173
|
|
|
331
|
|
|
338
|
|
||||
Impairment losses
|
—
|
|
|
89
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|
|
—
|
|
|
89
|
|
||||
Total costs and expenses
|
12,992
|
|
|
8,684
|
|
|
23,774
|
|
|
17,588
|
|
||||
OPERATING INCOME
|
1,126
|
|
|
743
|
|
|
2,226
|
|
|
1,500
|
|
||||
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
||||||||
Interest expense, net of interest capitalized
|
(510
|
)
|
|
(477
|
)
|
|
(976
|
)
|
|
(950
|
)
|
||||
Equity in earnings of unconsolidated affiliates
|
92
|
|
|
49
|
|
|
171
|
|
|
136
|
|
||||
Losses on extinguishments of debt
|
—
|
|
|
—
|
|
|
(106
|
)
|
|
(25
|
)
|
||||
Gains (losses) on interest rate derivatives
|
20
|
|
|
(25
|
)
|
|
72
|
|
|
(20
|
)
|
||||
Other, net
|
(1
|
)
|
|
57
|
|
|
56
|
|
|
74
|
|
||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
|
727
|
|
|
347
|
|
|
1,443
|
|
|
715
|
|
||||
Income tax expense from continuing operations
|
68
|
|
|
33
|
|
|
58
|
|
|
71
|
|
||||
INCOME FROM CONTINUING OPERATIONS
|
659
|
|
|
314
|
|
|
1,385
|
|
|
644
|
|
||||
Loss from discontinued operations, net of income taxes
|
(26
|
)
|
|
(193
|
)
|
|
(263
|
)
|
|
(204
|
)
|
||||
NET INCOME
|
633
|
|
|
121
|
|
|
1,122
|
|
|
440
|
|
||||
Less: Net income (loss) attributable to noncontrolling interest
|
278
|
|
|
(91
|
)
|
|
404
|
|
|
(11
|
)
|
||||
NET INCOME ATTRIBUTABLE TO PARTNERS
|
355
|
|
|
212
|
|
|
718
|
|
|
451
|
|
||||
Convertible Unitholders' interest in income
|
12
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|
|
8
|
|
|
33
|
|
|
14
|
|
||||
General Partner’s interest in net income
|
1
|
|
|
—
|
|
|
2
|
|
|
1
|
|
||||
Limited Partners’ interest in net income
|
$
|
342
|
|
|
$
|
204
|
|
|
$
|
683
|
|
|
$
|
436
|
|
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.31
|
|
|
$
|
0.20
|
|
|
$
|
0.63
|
|
|
$
|
0.41
|
|
Diluted
|
$
|
0.31
|
|
|
$
|
0.19
|
|
|
$
|
0.63
|
|
|
$
|
0.40
|
|
NET INCOME PER LIMITED PARTNER UNIT:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.31
|
|
|
$
|
0.19
|
|
|
$
|
0.62
|
|
|
$
|
0.40
|
|
Diluted
|
$
|
0.31
|
|
|
$
|
0.18
|
|
|
$
|
0.62
|
|
|
$
|
0.39
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
||||||||
Net income
|
$
|
633
|
|
|
$
|
121
|
|
|
$
|
1,122
|
|
|
$
|
440
|
|
Other comprehensive income, net of tax:
|
|
|
|
|
|
|
|
||||||||
Change in value of available-for-sale securities
|
—
|
|
|
1
|
|
|
(2
|
)
|
|
3
|
|
||||
Actuarial gain 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
|
635
|
|
|
120
|
|
|
1,125
|
|
|
439
|
|
||||
Less: Comprehensive income attributable to noncontrolling interest
|
280
|
|
|
(92
|
)
|
|
407
|
|
|
(12
|
)
|
||||
Comprehensive income attributable to partners
|
$
|
355
|
|
|
$
|
212
|
|
|
$
|
718
|
|
|
$
|
451
|
|
|
Series A Convertible Preferred Units
|
|
Common Unitholders
|
|
General Partner
|
|
Noncontrolling Interest
|
|
Total
|
||||||||||
Balance, December 31, 2017
|
$
|
450
|
|
|
$
|
(1,643
|
)
|
|
$
|
(3
|
)
|
|
$
|
31,176
|
|
|
$
|
29,980
|
|
Distributions to partners
|
—
|
|
|
(530
|
)
|
|
(2
|
)
|
|
—
|
|
|
(532
|
)
|
|||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,793
|
)
|
|
(1,793
|
)
|
|||||
Distributions reinvested
|
115
|
|
|
(115
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Subsidiary units repurchased
|
(7
|
)
|
|
(119
|
)
|
|
—
|
|
|
102
|
|
|
(24
|
)
|
|||||
Subsidiary units issued
|
—
|
|
|
1
|
|
|
—
|
|
|
488
|
|
|
489
|
|
|||||
Capital contributions received from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
318
|
|
|
318
|
|
|||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|||||
Cumulative effect adjustment due to change in accounting principle (see Note 1)
|
—
|
|
|
—
|
|
|
—
|
|
|
(54
|
)
|
|
(54
|
)
|
|||||
Acquisition of USAC
|
—
|
|
|
—
|
|
|
—
|
|
|
832
|
|
|
832
|
|
|||||
Series A Convertible Preferred Units conversion
|
(589
|
)
|
|
589
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other, net
|
(2
|
)
|
|
28
|
|
|
(1
|
)
|
|
17
|
|
|
42
|
|
|||||
Net income
|
33
|
|
|
683
|
|
|
2
|
|
|
404
|
|
|
1,122
|
|
|||||
Balance, June 30, 2018
|
$
|
—
|
|
|
$
|
(1,106
|
)
|
|
$
|
(4
|
)
|
|
$
|
31,493
|
|
|
$
|
30,383
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017*
|
||||
OPERATING ACTIVITIES
|
|
|
|
||||
Net income
|
$
|
1,122
|
|
|
$
|
440
|
|
Reconciliation of net income to net cash provided by operating activities:
|
|
|
|
||||
Loss from discontinued operations
|
263
|
|
|
204
|
|
||
Depreciation, depletion and amortization
|
1,359
|
|
|
1,235
|
|
||
Deferred income taxes
|
71
|
|
|
59
|
|
||
Amortization included in interest expense
|
10
|
|
|
9
|
|
||
Non-cash compensation expense
|
55
|
|
|
47
|
|
||
Impairment losses
|
—
|
|
|
89
|
|
||
Loss on extinguishment of debt
|
106
|
|
|
25
|
|
||
Equity in earnings of unconsolidated affiliates
|
(171
|
)
|
|
(136
|
)
|
||
Distributions from unconsolidated affiliates
|
138
|
|
|
125
|
|
||
Inventory valuation adjustments
|
(57
|
)
|
|
42
|
|
||
Distributions on unvested awards
|
(25
|
)
|
|
(18
|
)
|
||
Other non-cash
|
(66
|
)
|
|
(76
|
)
|
||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation
|
357
|
|
|
(582
|
)
|
||
Net cash provided by operating activities
|
3,162
|
|
|
1,463
|
|
||
INVESTING ACTIVITIES
|
|
|
|
||||
Cash received in USAC acquisition (net of cash paid)
|
461
|
|
|
—
|
|
||
Cash proceeds from sale of Bakken Pipeline interest
|
—
|
|
|
2,000
|
|
||
Cash paid for other acquisitions (net of cash received)
|
(143
|
)
|
|
(569
|
)
|
||
Capital expenditures (excluding allowance for equity funds used during construction)
|
(3,539
|
)
|
|
(2,879
|
)
|
||
Contributions in aid of construction costs
|
60
|
|
|
16
|
|
||
Contributions to unconsolidated affiliates
|
(13
|
)
|
|
(225
|
)
|
||
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
31
|
|
|
94
|
|
||
Proceeds from the sale of other assets
|
6
|
|
|
25
|
|
||
Other
|
—
|
|
|
1
|
|
||
Net cash used in by investing activities
|
(3,137
|
)
|
|
(1,537
|
)
|
||
FINANCING ACTIVITIES
|
|
|
|
||||
Proceeds from borrowings
|
16,702
|
|
|
14,950
|
|
||
Repayments of long-term debt
|
(18,039
|
)
|
|
(14,304
|
)
|
||
Cash paid on affiliate notes
|
—
|
|
|
(255
|
)
|
||
Subsidiary units repurchased
|
(24
|
)
|
|
—
|
|
||
Units issued for cash
|
—
|
|
|
568
|
|
||
Subsidiary units and warrants issued for cash
|
954
|
|
|
462
|
|
||
Distributions to partners
|
(532
|
)
|
|
(501
|
)
|
||
Debt issuance costs
|
(173
|
)
|
|
(35
|
)
|
||
Distributions to noncontrolling interests
|
(1,793
|
)
|
|
(1,401
|
)
|
||
Capital contributions from noncontrolling interest
|
318
|
|
|
456
|
|
Redemption of ETP Convertible Preferred Units
|
—
|
|
|
(53
|
)
|
||
Other, net
|
5
|
|
|
32
|
|
||
Net cash used in financing activities
|
(2,582
|
)
|
|
(81
|
)
|
||
DISCONTINUED OPERATIONS
|
|
|
|
||||
Operating activities
|
(478
|
)
|
|
131
|
|
||
Investing activities
|
3,207
|
|
|
(62
|
)
|
||
Changes in cash included in current assets held for sale
|
11
|
|
|
(2
|
)
|
||
Net increase in cash and cash equivalents of discontinued operations
|
2,740
|
|
|
67
|
|
||
Increase (decrease) in cash and cash equivalents
|
183
|
|
|
(88
|
)
|
||
Cash and cash equivalents, beginning of period
|
336
|
|
|
467
|
|
||
Cash and cash equivalents, end of period
|
$
|
519
|
|
|
$
|
379
|
|
1.
|
ORGANIZATION AND BASIS OF PRESENTATION
|
•
|
the Parent Company;
|
•
|
our controlled subsidiaries, ETP, Sunoco LP and, beginning April 2018, USAC;
|
•
|
consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDRs in ETP and Sunoco LP, and the general partner interests in USAC; and
|
•
|
our wholly-owned subsidiary, Lake Charles LNG.
|
•
|
Investment in ETP, including the consolidated operations of ETP;
|
•
|
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
|
•
|
Investment in USAC, including the consolidated operations of USAC;
|
•
|
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
|
•
|
Corporate and Other, including the following:
|
•
|
activities of the Parent Company; and
|
•
|
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
|
|
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
|
$
|
7,171
|
|
|
$
|
(4
|
)
|
|
$
|
7,167
|
|
|
$
|
14,710
|
|
|
$
|
(33
|
)
|
|
$
|
14,677
|
|
Operating income
|
739
|
|
|
4
|
|
|
743
|
|
|
1,467
|
|
|
33
|
|
|
1,500
|
|
||||||
Income before income tax expense
|
343
|
|
|
4
|
|
|
347
|
|
|
682
|
|
|
33
|
|
|
715
|
|
||||||
Net income
|
117
|
|
|
4
|
|
|
121
|
|
|
407
|
|
|
33
|
|
|
440
|
|
||||||
Net loss attributable to noncontrolling interest
|
(95
|
)
|
|
4
|
|
|
(91
|
)
|
|
(44
|
)
|
|
33
|
|
|
(11
|
)
|
||||||
Comprehensive income
|
116
|
|
|
4
|
|
|
120
|
|
|
406
|
|
|
33
|
|
|
439
|
|
|
Six Months Ended June 30, 2017
|
||||||||||
|
As Originally Reported*
|
|
Effect of Change
|
|
As Adjusted
|
||||||
Net income
|
$
|
407
|
|
|
$
|
33
|
|
|
$
|
440
|
|
Inventory Valuation Adjustments
|
98
|
|
|
(56
|
)
|
|
42
|
|
|||
Net change in operating assets and liabilities (change in inventories)
|
(605
|
)
|
|
23
|
|
|
(582
|
)
|
|
Balance at December 31, 2017
|
|
Adjustments due to ASC 606
|
|
Balance at January 1, 2018
|
||||||
Assets:
|
|
|
|
|
|
||||||
Other current assets
|
$
|
295
|
|
|
$
|
8
|
|
|
$
|
303
|
|
Property and Equipment, net
|
61,088
|
|
|
—
|
|
|
61,088
|
|
|||
Other non-current assets, net
|
886
|
|
|
39
|
|
|
925
|
|
|||
Intangible assets, net
|
6,116
|
|
|
(100
|
)
|
|
6,016
|
|
|||
|
|
|
|
|
|
||||||
Liabilities and Equity:
|
|
|
|
|
|
||||||
Other non-current liabilities
|
$
|
1,217
|
|
|
$
|
1
|
|
|
$
|
1,218
|
|
Noncontrolling interest
|
31,176
|
|
|
(54
|
)
|
|
31,122
|
|
|
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
|
1,667
|
|
|
1,814
|
|
|
(147
|
)
|
|
3,097
|
|
|
3,430
|
|
|
(333
|
)
|
||||||
Refined product sales
|
4,818
|
|
|
4,831
|
|
|
(13
|
)
|
|
8,628
|
|
|
8,651
|
|
|
(23
|
)
|
||||||
Other
|
227
|
|
|
227
|
|
|
—
|
|
|
523
|
|
|
523
|
|
|
—
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cost of products sold
|
$
|
11,343
|
|
|
$
|
11,491
|
|
|
$
|
(148
|
)
|
|
$
|
20,588
|
|
|
$
|
20,923
|
|
|
$
|
(335
|
)
|
Operating expenses
|
772
|
|
|
764
|
|
|
8
|
|
|
1,496
|
|
|
1,475
|
|
|
21
|
|
||||||
Depreciation and amortization
|
694
|
|
|
701
|
|
|
(7
|
)
|
|
1,359
|
|
|
1,372
|
|
|
(13
|
)
|
|
June 30, 2018
|
||||||||||
|
As Reported
|
|
Balances Without Adoption of ASC 606
|
|
Effect of Change: Higher/(Lower)
|
||||||
Assets:
|
|
|
|
|
|
||||||
Other current assets
|
$
|
616
|
|
|
$
|
607
|
|
|
$
|
9
|
|
Property and Equipment, net
|
64,880
|
|
|
64,880
|
|
|
—
|
|
|||
Intangible assets, net
|
6,088
|
|
|
6,200
|
|
|
(112
|
)
|
|||
Other non-current assets, net
|
996
|
|
|
950
|
|
|
46
|
|
|||
|
|
|
|
|
|
||||||
Liabilities and Equity:
|
|
|
|
|
|
||||||
Other non-current liabilities
|
$
|
1,227
|
|
|
$
|
1,226
|
|
|
$
|
1
|
|
Noncontrolling interest
|
31,493
|
|
|
31,551
|
|
|
(58
|
)
|
2.
|
ACQUISITIONS AND OTHER INVESTING TRANSACTIONS
|
|
|
At April 2, 2018
|
||
Total current assets
|
|
$
|
786
|
|
Property, plant and equipment
|
|
1,332
|
|
|
Other non-current assets
|
|
15
|
|
|
Goodwill
(1)
|
|
366
|
|
|
Intangible assets
|
|
222
|
|
|
|
|
2,721
|
|
|
|
|
|
||
Total current liabilities
|
|
110
|
|
|
Long-term debt, less current maturities
|
|
1,527
|
|
|
Other non-current liabilities
|
|
2
|
|
|
|
|
1,639
|
|
|
|
|
|
||
Noncontrolling interest
|
|
832
|
|
|
|
|
|
||
Total consideration
|
|
250
|
|
|
Cash received
(2)
|
|
711
|
|
|
Total consideration, net of cash received
(2)
|
|
$
|
(461
|
)
|
(1)
|
None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations.
|
(2)
|
Cash received represents cash and cash equivalents held by USAC as of the acquisition date.
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Carrying amount of assets classified as held for sale:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
21
|
|
Inventories
|
—
|
|
|
149
|
|
||
Other current assets
|
—
|
|
|
16
|
|
||
Property, plant and equipment, net
|
6
|
|
|
1,851
|
|
||
Goodwill
|
—
|
|
|
796
|
|
||
Intangible assets, net
|
—
|
|
|
477
|
|
||
Other non-current assets, net
|
—
|
|
|
3
|
|
||
Total assets classified as held for sale in the Consolidated Balance Sheet
|
$
|
6
|
|
|
$
|
3,313
|
|
|
|
|
|
||||
Carrying amount of liabilities classified as held for sale:
|
|
|
|
||||
Other current and non-current liabilities
|
$
|
—
|
|
|
$
|
75
|
|
Total liabilities classified as held for sale in the Consolidated Balance Sheet
|
$
|
—
|
|
|
$
|
75
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
NON-CASH INVESTING ACTIVITIES:
|
|
|
|
||||
Accrued capital expenditures
|
$
|
1,015
|
|
|
$
|
1,364
|
|
Losses from subsidiary common unit transactions
|
(125
|
)
|
|
(51
|
)
|
||
NON-CASH FINANCING ACTIVITIES:
|
|
|
|
||||
Contribution of property, plant and equipment from noncontrolling interest
|
$
|
—
|
|
|
$
|
988
|
|
Conversion of Series A Convertible Preferred Units to common units
|
589
|
|
|
—
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Natural gas, NGLs, and refined products
|
$
|
873
|
|
|
$
|
1,120
|
|
Crude oil
|
571
|
|
|
551
|
|
||
Spare parts and other
|
358
|
|
|
351
|
|
||
Total inventories
|
$
|
1,802
|
|
|
$
|
2,022
|
|
|
|
|
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
|
301
|
|
|
301
|
|
|
—
|
|
|||
Refined Products — Futures
|
3
|
|
|
3
|
|
|
—
|
|
|||
Crude — Forwards/Swaps
|
1
|
|
|
1
|
|
|
—
|
|
|||
Corn (Bushels)
|
1
|
|
|
1
|
|
|
—
|
|
|||
Total commodity derivatives
|
419
|
|
|
340
|
|
|
79
|
|
|||
Other non-current assets
|
21
|
|
|
14
|
|
|
7
|
|
|||
Total assets
|
$
|
440
|
|
|
$
|
354
|
|
|
$
|
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
|
(319
|
)
|
|
(319
|
)
|
|
—
|
|
|||
Refined Products — Futures
|
(9
|
)
|
|
(9
|
)
|
|
—
|
|
|||
Crude — Forwards/Swaps
|
(308
|
)
|
|
(308
|
)
|
|
—
|
|
|||
Total commodity derivatives
|
(784
|
)
|
|
(721
|
)
|
|
(63
|
)
|
|||
Total liabilities
|
$
|
(931
|
)
|
|
$
|
(721
|
)
|
|
$
|
(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
|
|
|
—
|
|
|||
Refined Products — Futures
|
1
|
|
|
1
|
|
|
—
|
|
|||
Crude:
|
|
|
|
|
|
||||||
Forwards/Swaps
|
2
|
|
|
2
|
|
|
—
|
|
|||
Futures
|
2
|
|
|
2
|
|
|
—
|
|
|||
Total commodity derivatives
|
321
|
|
|
277
|
|
|
44
|
|
|||
Other non-current assets
|
21
|
|
|
14
|
|
|
7
|
|
|||
Total assets
|
$
|
342
|
|
|
$
|
291
|
|
|
$
|
51
|
|
Liabilities:
|
|
|
|
|
|
||||||
Interest rate derivatives
|
$
|
(219
|
)
|
|
$
|
—
|
|
|
$
|
(219
|
)
|
Commodity derivatives:
|
|
|
|
|
|
||||||
Natural Gas:
|
|
|
|
|
|
||||||
Basis Swaps IFERC/NYMEX
|
(24
|
)
|
|
(24
|
)
|
|
—
|
|
|||
Swing Swaps IFERC
|
(15
|
)
|
|
(1
|
)
|
|
(14
|
)
|
|||
Fixed Swaps/Futures
|
(57
|
)
|
|
(57
|
)
|
|
—
|
|
|||
Forward Physical Swaps
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|||
Power — Forwards
|
(22
|
)
|
|
—
|
|
|
(22
|
)
|
|||
NGLs — Forwards/Swaps
|
(186
|
)
|
|
(186
|
)
|
|
—
|
|
|||
Refined Products — Futures
|
(28
|
)
|
|
(28
|
)
|
|
—
|
|
|||
Crude:
|
|
|
|
|
|
||||||
Forwards/Swaps
|
(6
|
)
|
|
(6
|
)
|
|
—
|
|
|||
Futures
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Total commodity derivatives
|
(341
|
)
|
|
(303
|
)
|
|
(38
|
)
|
|||
Total liabilities
|
$
|
(560
|
)
|
|
$
|
(303
|
)
|
|
$
|
(257
|
)
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
||||||||
Income from continuing operations
|
$
|
659
|
|
|
$
|
314
|
|
|
$
|
1,385
|
|
|
$
|
644
|
|
Less: Income from continuing operations attributable to noncontrolling interest
|
303
|
|
|
94
|
|
|
657
|
|
|
185
|
|
||||
Income from continuing operations, net of noncontrolling interest
|
356
|
|
|
220
|
|
|
728
|
|
|
459
|
|
||||
Less: Convertible Unitholders’ interest in income
|
12
|
|
|
8
|
|
|
33
|
|
|
14
|
|
||||
Less: General Partner’s interest in income
|
1
|
|
|
—
|
|
|
2
|
|
|
1
|
|
||||
Income from continuing operations available to Limited Partners
|
$
|
343
|
|
|
$
|
212
|
|
|
$
|
693
|
|
|
$
|
444
|
|
Basic Income from Continuing Operations per Limited Partner Unit:
|
|
|
|
|
|
|
|
||||||||
Weighted average limited partner units
|
1,114.8
|
|
|
1,075.2
|
|
|
1,097.1
|
|
|
1,077.2
|
|
||||
Basic income from continuing operations per Limited Partner unit
|
$
|
0.31
|
|
|
$
|
0.20
|
|
|
$
|
0.63
|
|
|
$
|
0.41
|
|
Basic income from discontinued operations per Limited Partner unit
|
$
|
0.00
|
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
Diluted Income from Continuing Operations per Limited Partner Unit:
|
|
|
|
|
|
|
|
||||||||
Income from continuing operations available to Limited Partners
|
$
|
343
|
|
|
$
|
212
|
|
|
$
|
693
|
|
|
$
|
444
|
|
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders
|
12
|
|
|
8
|
|
|
33
|
|
|
14
|
|
||||
Diluted income from continuing operations available to Limited Partners
|
$
|
355
|
|
|
$
|
220
|
|
|
$
|
726
|
|
|
$
|
458
|
|
Weighted average limited partner units
|
1,114.8
|
|
|
1,075.2
|
|
|
1,097.1
|
|
|
1,077.2
|
|
||||
Dilutive effect of unconverted unit awards and Convertible Units
|
43.4
|
|
|
66.1
|
|
|
61.1
|
|
|
66.5
|
|
||||
Diluted weighted average limited partner units
|
1,158.2
|
|
|
1,141.3
|
|
|
1,158.2
|
|
|
1,143.7
|
|
||||
Diluted income from continuing operations per Limited Partner unit
|
$
|
0.31
|
|
|
$
|
0.19
|
|
|
$
|
0.63
|
|
|
$
|
0.40
|
|
Diluted income from discontinued operations per Limited Partner unit
|
$
|
0.00
|
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
•
|
redeem in full its existing senior notes, comprised of
$800 million
in aggregate principal amount of
6.250%
senior notes due 2021,
$600 million
in aggregate principal amount of
5.500%
senior notes due 2020, and
$800 million
in aggregate principal amount of
6.375%
senior notes due 2023;
|
•
|
repay in full and terminate its term loan;
|
•
|
pay all closing costs in connection with the 7-Eleven transaction;
|
•
|
redeem the outstanding Sunoco LP Series A Preferred Units; and
|
•
|
repurchase
17,286,859
Sunoco LP common units owned by ETP.
|
|
Number of ETE Series A Convertible Preferred Units
|
|
Number of Common Units
|
||
Outstanding at December 31, 2017
|
329.3
|
|
|
1,079.1
|
|
Conversion of ETE Series A Convertible Preferred Units to common units
|
(329.3
|
)
|
|
79.1
|
|
Outstanding at June 30, 2018
|
—
|
|
|
1,158.2
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2017
(1)
|
|
February 8, 2018
|
|
February 20, 2018
|
|
$
|
0.3050
|
|
March 31, 2018
(1)
|
|
May 7, 2018
|
|
May 21, 2018
|
|
0.3050
|
|
|
June 30, 2018
|
|
August 6, 2018
|
|
August 20, 2018
|
|
0.3050
|
|
(1)
|
Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forgo their cash distributions on all or a portion of their common units, and in lieu of receiving cash distributions on these common units for each such quarter, such unitholder received Series A Convertible Preferred Units, and (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to
$0.11
per Series A Convertible Preferred Unit. The quarter ended March 31, 2018 was the final quarter of participation in the plan.
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2017
|
|
February 8, 2018
|
|
February 20, 2018
|
|
$
|
0.1100
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 21, 2018
|
|
0.1100
|
|
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
|
||
ETP 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
|
|
|
ETP 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
|
|
|
ETP Series C Preferred Units
|
|
|
|
|
|
|
||
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
0.563
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2017
|
|
February 6, 2018
|
|
February 14, 2018
|
|
$
|
0.8255
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 15, 2018
|
|
0.8255
|
|
|
June 30, 2018
|
|
August 7, 2018
|
|
August 15, 2018
|
|
0.8255
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
March 31, 2018
|
|
May 1, 2018
|
|
May 11, 2018
|
|
$
|
0.5250
|
|
June 30, 2018
|
|
July 30, 2018
|
|
August 10, 2018
|
|
0.5250
|
|
|
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
|
|
||
Subtotal
|
4
|
|
|
3
|
|
||
Amounts attributable to noncontrolling interest
|
(4
|
)
|
|
(3
|
)
|
||
Total AOCI, net of tax
|
$
|
—
|
|
|
$
|
—
|
|
(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 ETP’s accumulated other comprehensive income related to available-for-sale securities to ETP’s common unitholders. The amount is reflected as a change in noncontrolling interest in the Partnership’s consolidated financial statements.
|
10.
|
INCOME TAXES
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Rental expense
(1)
|
$
|
42
|
|
|
$
|
41
|
|
|
$
|
74
|
|
|
$
|
81
|
|
Less: Sublease rental income
|
(11
|
)
|
|
(6
|
)
|
|
(17
|
)
|
|
(12
|
)
|
||||
Rental expense, net
|
$
|
31
|
|
|
$
|
35
|
|
|
$
|
57
|
|
|
$
|
69
|
|
(1)
|
Includes contingent rentals totaling
$1 million
and
$6 million
for
three months ended June 30,
2018
and
2017
, respectively and
$2 million
and
$10 million
for the six months ended June 30, 2018 and 2017, respectively.
|
•
|
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
|
$
|
51
|
|
|
$
|
35
|
|
Non-current
|
352
|
|
|
337
|
|
||
Total environmental liabilities
|
$
|
403
|
|
|
$
|
372
|
|
•
|
intrastate transportation and storage
|
•
|
interstate transportation and storage
|
•
|
midstream
|
•
|
NGL and refined products transportation and services
|
•
|
crude oil transportation and services
|
•
|
all other
|
•
|
fuel distribution and marketing
|
•
|
all other
|
•
|
contract operations
|
•
|
retail parts and services
|
•
|
station installations
|
•
|
terminal services
|
•
|
In-Kind POP:
ETP retains its POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. ETP recognizes revenue for the non-cash consideration and cash fees at the time the services are performed.
|
•
|
Mixed POP:
ETP purchases NGLs from the producer and retains a portion of the residue gas as non-cash consideration for services provided. ETP 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 NGL’s ETP purchased and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, ETP split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.
|
|
Balance at
January 1, 2018
|
|
Balance at June 30, 2018
|
|
Increase/ (Decrease)
|
||||||
Contract Balances
|
|
|
|
|
|
||||||
Contract Asset
|
$
|
51
|
|
|
$
|
59
|
|
|
$
|
8
|
|
Accounts receivable from contracts with customers
|
445
|
|
|
487
|
|
|
42
|
|
|||
Contract Liability
|
1
|
|
|
1
|
|
|
—
|
|
|
|
2018 (remainder)
|
|
2019
|
|
2020
|
|
Thereafter
|
|
Total
|
||||||||||
Revenue expected to be recognized on contracts with customers existing as of June 30, 2018
|
|
$
|
2,694
|
|
|
$
|
5,240
|
|
|
$
|
4,732
|
|
|
$
|
29,258
|
|
|
$
|
41,924
|
|
•
|
Right to invoice:
The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.
|
•
|
Significant financing component:
The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.
|
•
|
Unearned variable consideration:
The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.
|
•
|
Incremental costs of obtaining a contract:
The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.
|
•
|
Shipping and handling costs:
The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.
|
•
|
Measurement of transaction price:
The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc).
|
•
|
Variable consideration of wholly unsatisfied performance obligations:
The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.
|
|
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
|
5,460
|
|
|
2018-2019
|
|
(4,390
|
)
|
|
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
|
44,335
|
|
|
2018-2019
|
|
9,237
|
|
|
2018-2019
|
Refined Products (MBbls) – Futures
|
(776
|
)
|
|
2018-2021
|
|
(3,901
|
)
|
|
2018-2019
|
Corn (thousand bushels)
|
(3,320
|
)
|
|
2018-2019
|
|
1,870
|
|
|
2018
|
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.
|
|
|
|
|
Notional Amount Outstanding
|
||||||
Term
|
|
Type
(1)
|
|
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 a term 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
|
112
|
|
|
45
|
|
|
(430
|
)
|
|
(58
|
)
|
||||
Interest rate derivatives
|
—
|
|
|
—
|
|
|
(147
|
)
|
|
(219
|
)
|
||||
|
419
|
|
|
307
|
|
|
(929
|
)
|
|
(558
|
)
|
||||
Total derivatives
|
$
|
419
|
|
|
$
|
321
|
|
|
$
|
(931
|
)
|
|
$
|
(560
|
)
|
|
|
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
|
|
(295
|
)
|
|
17
|
|
|
(366
|
)
|
|
19
|
|
||||
Interest rate derivatives
|
|
Gains (losses) on interest rate derivatives
|
|
20
|
|
|
(25
|
)
|
|
72
|
|
|
(20
|
)
|
||||
Embedded derivatives
|
|
Other, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Total
|
|
|
|
$
|
(259
|
)
|
|
$
|
7
|
|
|
$
|
(261
|
)
|
|
$
|
26
|
|
•
|
Investment in ETP, including the consolidated operations of ETP;
|
•
|
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
|
•
|
Investment in USAC, including the consolidated operations of USAC;
|
•
|
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
|
•
|
Corporate and Other, including the following:
|
•
|
activities of the Parent Company; and
|
•
|
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
||||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
|
|
||||||||
Investment in ETP
|
$
|
2,051
|
|
|
$
|
1,545
|
|
|
$
|
3,932
|
|
|
$
|
2,990
|
|
Investment in Sunoco LP
|
140
|
|
|
220
|
|
|
249
|
|
|
375
|
|
||||
Investment in USAC
|
95
|
|
|
—
|
|
|
95
|
|
|
—
|
|
||||
Investment in Lake Charles LNG
|
45
|
|
|
44
|
|
|
88
|
|
|
88
|
|
||||
Corporate and Other
|
(9
|
)
|
|
(9
|
)
|
|
(8
|
)
|
|
(22
|
)
|
||||
Adjustments and Eliminations
|
(60
|
)
|
|
(83
|
)
|
|
(92
|
)
|
|
(137
|
)
|
||||
Total
|
2,262
|
|
|
1,717
|
|
|
4,264
|
|
|
3,294
|
|
||||
Depreciation, depletion and amortization
|
(694
|
)
|
|
(607
|
)
|
|
(1,359
|
)
|
|
(1,235
|
)
|
||||
Interest expense, net of interest capitalized
|
(510
|
)
|
|
(477
|
)
|
|
(976
|
)
|
|
(950
|
)
|
||||
Impairment losses
|
—
|
|
|
(89
|
)
|
|
—
|
|
|
(89
|
)
|
||||
Gains (losses) on interest rate derivatives
|
20
|
|
|
(25
|
)
|
|
72
|
|
|
(20
|
)
|
||||
Non-cash compensation expense
|
(32
|
)
|
|
(20
|
)
|
|
(55
|
)
|
|
(47
|
)
|
||||
Unrealized gains (losses) on commodity risk management activities
|
(265
|
)
|
|
29
|
|
|
(352
|
)
|
|
98
|
|
||||
Losses on extinguishments of debt
|
—
|
|
|
—
|
|
|
(106
|
)
|
|
(25
|
)
|
||||
Inventory valuation adjustments
|
32
|
|
|
(29
|
)
|
|
57
|
|
|
(42
|
)
|
||||
Equity in earnings of unconsolidated affiliates
|
92
|
|
|
49
|
|
|
171
|
|
|
136
|
|
||||
Adjusted EBITDA related to unconsolidated affiliates
|
(168
|
)
|
|
(164
|
)
|
|
(324
|
)
|
|
(349
|
)
|
||||
Adjusted EBITDA related to discontinued operations
|
5
|
|
|
(72
|
)
|
|
25
|
|
|
(103
|
)
|
||||
Other, net
|
(15
|
)
|
|
35
|
|
|
26
|
|
|
47
|
|
||||
Income from continuing operations before income tax expense
|
727
|
|
|
347
|
|
|
1,443
|
|
|
715
|
|
||||
Income tax expense from continuing operations
|
(68
|
)
|
|
(33
|
)
|
|
(58
|
)
|
|
(71
|
)
|
||||
Income from continuing operations
|
659
|
|
|
314
|
|
|
1,385
|
|
|
644
|
|
||||
Loss from discontinued operations, net of income taxes
|
(26
|
)
|
|
(193
|
)
|
|
(263
|
)
|
|
(204
|
)
|
||||
Net income
|
$
|
633
|
|
|
$
|
121
|
|
|
$
|
1,122
|
|
|
$
|
440
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Assets:
|
|
|
|
||||
Investment in ETP
|
$
|
78,570
|
|
|
$
|
77,965
|
|
Investment in Sunoco LP
|
5,006
|
|
|
8,344
|
|
||
Investment in USAC
|
3,785
|
|
|
—
|
|
||
Investment in Lake Charles LNG
|
1,710
|
|
|
1,646
|
|
||
Corporate and Other
|
585
|
|
|
598
|
|
||
Adjustments and Eliminations
|
(2,239
|
)
|
|
(2,307
|
)
|
||
Total assets
|
$
|
87,417
|
|
|
$
|
86,246
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
||||||||
Revenues:
|
|
|
|
|
|
|
|
||||||||
Investment in ETP:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
$
|
9,298
|
|
|
$
|
6,485
|
|
|
$
|
17,383
|
|
|
$
|
13,292
|
|
Intersegment revenues
|
112
|
|
|
91
|
|
|
307
|
|
|
179
|
|
||||
|
9,410
|
|
|
6,576
|
|
|
17,690
|
|
|
13,471
|
|
||||
Investment in Sunoco LP:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
4,606
|
|
|
2,892
|
|
|
8,354
|
|
|
5,697
|
|
||||
Intersegment revenues
|
1
|
|
|
—
|
|
|
2
|
|
|
3
|
|
||||
|
4,607
|
|
|
2,892
|
|
|
8,356
|
|
|
5,700
|
|
||||
Investment in USAC:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
165
|
|
|
—
|
|
|
165
|
|
|
—
|
|
||||
Intersegment revenues
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
||||
|
167
|
|
|
—
|
|
|
167
|
|
|
—
|
|
||||
Investment in Lake Charles LNG:
|
|
|
|
|
|
|
|
||||||||
Revenues from external customers
|
49
|
|
|
50
|
|
|
98
|
|
|
99
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Adjustments and Eliminations
|
(115
|
)
|
|
(91
|
)
|
|
(311
|
)
|
|
(182
|
)
|
||||
Total revenues
|
$
|
14,118
|
|
|
$
|
9,427
|
|
|
$
|
26,000
|
|
|
$
|
19,088
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
||||||||
Intrastate transportation and storage
|
$
|
761
|
|
|
$
|
699
|
|
|
$
|
1,578
|
|
|
$
|
1,467
|
|
Interstate transportation and storage
|
323
|
|
|
201
|
|
|
636
|
|
|
432
|
|
||||
Midstream
|
594
|
|
|
633
|
|
|
1,034
|
|
|
1,198
|
|
||||
NGL and refined products transportation and services
|
2,472
|
|
|
1,767
|
|
|
4,930
|
|
|
3,885
|
|
||||
Crude oil transportation and services
|
4,789
|
|
|
2,460
|
|
|
8,520
|
|
|
5,035
|
|
||||
All Other
|
471
|
|
|
816
|
|
|
992
|
|
|
1,454
|
|
||||
Total revenues
|
9,410
|
|
|
6,576
|
|
|
17,690
|
|
|
13,471
|
|
||||
Less: Intersegment revenues
|
112
|
|
|
91
|
|
|
307
|
|
|
179
|
|
||||
Revenues from external customers
|
$
|
9,298
|
|
|
$
|
6,485
|
|
|
$
|
17,383
|
|
|
$
|
13,292
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Fuel distribution and marketing
|
$
|
4,350
|
|
|
$
|
2,318
|
|
|
$
|
7,489
|
|
|
$
|
4,615
|
|
All other
|
257
|
|
|
574
|
|
|
867
|
|
|
1,085
|
|
||||
Total revenues
|
4,607
|
|
|
2,892
|
|
|
8,356
|
|
|
5,700
|
|
||||
Less: Intersegment revenues
|
1
|
|
|
—
|
|
|
2
|
|
|
3
|
|
||||
Revenues from external customers
|
$
|
4,606
|
|
|
$
|
2,892
|
|
|
$
|
8,354
|
|
|
$
|
5,697
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Contract operations
|
$
|
160
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
—
|
|
Retail parts and services
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
||||
Station installations revenue
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
Total revenues
|
167
|
|
|
—
|
|
|
167
|
|
|
—
|
|
||||
Less: Intersegment revenues
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
||||
Revenues from external customers
|
$
|
165
|
|
|
$
|
—
|
|
|
$
|
165
|
|
|
$
|
—
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
1
|
|
|
$
|
1
|
|
Accounts receivable from related companies
|
58
|
|
|
65
|
|
||
Other current assets
|
—
|
|
|
1
|
|
||
Total current assets
|
59
|
|
|
67
|
|
||
Property, plant and equipment, net
|
27
|
|
|
27
|
|
||
Advances to and investments in unconsolidated affiliates
|
6,042
|
|
|
6,082
|
|
||
Goodwill
|
9
|
|
|
9
|
|
||
Other non-current assets, net
|
7
|
|
|
8
|
|
||
Total assets
|
$
|
6,144
|
|
|
$
|
6,193
|
|
LIABILITIES AND PARTNERS’ DEFICIT
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Interest payable
|
$
|
70
|
|
|
$
|
66
|
|
Accrued and other current liabilities
|
8
|
|
|
4
|
|
||
Total current liabilities
|
78
|
|
|
70
|
|
||
Long-term debt, less current maturities
|
6,472
|
|
|
6,700
|
|
||
Long-term notes payable – related companies
|
702
|
|
|
617
|
|
||
Other non-current liabilities
|
2
|
|
|
2
|
|
||
Commitments and contingencies
|
|
|
|
||||
Partners’ deficit:
|
|
|
|
||||
Limited Partners:
|
|
|
|
||||
Series A Convertible Preferred Units
|
—
|
|
|
450
|
|
||
Common Unitholders
|
(1,106
|
)
|
|
(1,643
|
)
|
||
General Partner
|
(4
|
)
|
|
(3
|
)
|
||
Total partners’ deficit
|
(1,110
|
)
|
|
(1,196
|
)
|
||
Total liabilities and partners’ deficit
|
$
|
6,144
|
|
|
$
|
6,193
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES
|
$
|
(9
|
)
|
|
$
|
(9
|
)
|
|
$
|
(11
|
)
|
|
$
|
(22
|
)
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
||||||||
Interest expense, net
|
(90
|
)
|
|
(86
|
)
|
|
(176
|
)
|
|
(169
|
)
|
||||
Equity in earnings of unconsolidated affiliates
|
454
|
|
|
308
|
|
|
902
|
|
|
669
|
|
||||
Losses on extinguishments of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
||||
Other, net
|
—
|
|
|
(1
|
)
|
|
3
|
|
|
(2
|
)
|
||||
NET INCOME
|
355
|
|
|
212
|
|
|
718
|
|
|
451
|
|
||||
Convertible Unitholders’ interest in income
|
12
|
|
|
8
|
|
|
33
|
|
|
14
|
|
||||
General Partner’s interest in net income
|
1
|
|
|
—
|
|
|
2
|
|
|
1
|
|
||||
Limited Partners’ interest in net income
|
$
|
342
|
|
|
$
|
204
|
|
|
$
|
683
|
|
|
$
|
436
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES
|
$
|
626
|
|
|
$
|
405
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
||||
Contributions to unconsolidated affiliate
|
(250
|
)
|
|
(861
|
)
|
||
Capital expenditures
|
—
|
|
|
(1
|
)
|
||
Contributions in aid of construction costs
|
—
|
|
|
6
|
|
||
Sunoco LP Series A Preferred Units redemption
|
303
|
|
|
—
|
|
||
Net cash provided by (used in) investing activities
|
53
|
|
|
(856
|
)
|
||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
||||
Proceeds from borrowings
|
355
|
|
|
2,072
|
|
||
Principal payments on debt
|
(587
|
)
|
|
(1,740
|
)
|
||
Proceeds from affiliate
|
85
|
|
|
87
|
|
||
Distributions to partners
|
(532
|
)
|
|
(501
|
)
|
||
Units issued for cash
|
—
|
|
|
568
|
|
||
Debt issuance costs
|
—
|
|
|
(35
|
)
|
||
Net cash provided by (used in) financing activities
|
(679
|
)
|
|
451
|
|
||
CHANGE IN CASH AND CASH EQUIVALENTS
|
—
|
|
|
—
|
|
||
CASH AND CASH EQUIVALENTS, beginning of period
|
1
|
|
|
2
|
|
||
CASH AND CASH EQUIVALENTS, end of period
|
$
|
1
|
|
|
$
|
2
|
|
•
|
Investment in ETP, including the consolidated operations of ETP;
|
•
|
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
|
•
|
Investment in USAC, including the consolidated operations of USAC;
|
•
|
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
|
•
|
Corporate and Other, including the following:
|
•
|
activities of the Parent Company; and
|
•
|
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017*
|
|
Change
|
|
2018
|
|
2017*
|
|
Change
|
||||||||||||
Segment Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Investment in ETP
|
$
|
2,051
|
|
|
$
|
1,545
|
|
|
$
|
506
|
|
|
$
|
3,932
|
|
|
$
|
2,990
|
|
|
$
|
942
|
|
Investment in Sunoco LP
|
140
|
|
|
220
|
|
|
(80
|
)
|
|
249
|
|
|
375
|
|
|
(126
|
)
|
||||||
Investment in USAC
|
95
|
|
|
—
|
|
|
95
|
|
|
95
|
|
|
—
|
|
|
95
|
|
||||||
Investment in Lake Charles LNG
|
45
|
|
|
44
|
|
|
1
|
|
|
88
|
|
|
88
|
|
|
—
|
|
||||||
Corporate and Other
|
(9
|
)
|
|
(9
|
)
|
|
—
|
|
|
(8
|
)
|
|
(22
|
)
|
|
14
|
|
||||||
Adjustments and Eliminations
|
(60
|
)
|
|
(83
|
)
|
|
23
|
|
|
(92
|
)
|
|
(137
|
)
|
|
45
|
|
||||||
Total
|
2,262
|
|
|
1,717
|
|
|
545
|
|
|
4,264
|
|
|
3,294
|
|
|
970
|
|
||||||
Depreciation, depletion and amortization
|
(694
|
)
|
|
(607
|
)
|
|
(87
|
)
|
|
(1,359
|
)
|
|
(1,235
|
)
|
|
(124
|
)
|
||||||
Interest expense, net of interest capitalized
|
(510
|
)
|
|
(477
|
)
|
|
(33
|
)
|
|
(976
|
)
|
|
(950
|
)
|
|
(26
|
)
|
||||||
Impairment losses
|
—
|
|
|
(89
|
)
|
|
89
|
|
|
—
|
|
|
(89
|
)
|
|
89
|
|
||||||
Gains (losses) on interest rate derivatives
|
20
|
|
|
(25
|
)
|
|
45
|
|
|
72
|
|
|
(20
|
)
|
|
92
|
|
||||||
Non-cash compensation expense
|
(32
|
)
|
|
(20
|
)
|
|
(12
|
)
|
|
(55
|
)
|
|
(47
|
)
|
|
(8
|
)
|
||||||
Unrealized gains (losses) on commodity risk management activities
|
(265
|
)
|
|
29
|
|
|
(294
|
)
|
|
(352
|
)
|
|
98
|
|
|
(450
|
)
|
||||||
Losses on extinguishments of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
(106
|
)
|
|
(25
|
)
|
|
(81
|
)
|
||||||
Inventory valuation adjustments
|
32
|
|
|
(29
|
)
|
|
61
|
|
|
57
|
|
|
(42
|
)
|
|
99
|
|
||||||
Equity in earnings of unconsolidated affiliates
|
92
|
|
|
49
|
|
|
43
|
|
|
171
|
|
|
136
|
|
|
35
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
|
(168
|
)
|
|
(164
|
)
|
|
(4
|
)
|
|
(324
|
)
|
|
(349
|
)
|
|
25
|
|
||||||
Adjusted EBITDA related to discontinued operations
|
5
|
|
|
(72
|
)
|
|
77
|
|
|
25
|
|
|
(103
|
)
|
|
128
|
|
||||||
Other, net
|
(15
|
)
|
|
35
|
|
|
(50
|
)
|
|
26
|
|
|
47
|
|
|
(21
|
)
|
||||||
Income from continuing operations before income tax benefit expense
|
727
|
|
|
347
|
|
|
380
|
|
|
1,443
|
|
|
715
|
|
|
728
|
|
||||||
Income tax expense from continuing operations
|
(68
|
)
|
|
(33
|
)
|
|
(35
|
)
|
|
(58
|
)
|
|
(71
|
)
|
|
13
|
|
||||||
Income from continuing operations
|
659
|
|
|
314
|
|
|
345
|
|
|
1,385
|
|
|
644
|
|
|
741
|
|
||||||
Loss from discontinued operations, net of income taxes
|
(26
|
)
|
|
(193
|
)
|
|
167
|
|
|
(263
|
)
|
|
(204
|
)
|
|
(59
|
)
|
||||||
Net income
|
$
|
633
|
|
|
$
|
121
|
|
|
$
|
512
|
|
|
$
|
1,122
|
|
|
$
|
440
|
|
|
$
|
682
|
|
•
|
increases of
$22 million
and
$36 million
, respectively, of expense recognized by ETP compared to the same periods in the prior year primarily attributable to increases in long-term debt; and
|
•
|
increases of
$4 million
and
$7 million
, respectively, of expense recognized by the Parent company compared to the same periods in the prior year primarily attributable to increases in variable interest rates;
|
•
|
an increase of
$26 million
for both periods, due to the consolidation of USAC beginning April 2, 2018; partially offset by
|
•
|
decreases of
$18 million
and
$42 million
, respectively, of expense recognized by Sunoco LP compared to the same periods in the prior year primarily due to Sunoco LP’s repayment of its term loan and decreased borrowings under its revolving credit facility.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017*
|
|
Change
|
|
2018
|
|
2017*
|
|
Change
|
||||||||||||
Revenues
|
$
|
9,410
|
|
|
$
|
6,576
|
|
|
$
|
2,834
|
|
|
$
|
17,690
|
|
|
$
|
13,471
|
|
|
$
|
4,219
|
|
Cost of products sold
|
7,140
|
|
|
4,624
|
|
|
2,516
|
|
|
13,128
|
|
|
9,674
|
|
|
3,454
|
|
||||||
Unrealized (gains) losses on commodity risk management activities
|
265
|
|
|
(34
|
)
|
|
299
|
|
|
352
|
|
|
(98
|
)
|
|
450
|
|
||||||
Operating expenses, excluding non-cash compensation expense
|
(615
|
)
|
|
(532
|
)
|
|
(83
|
)
|
|
(1,202
|
)
|
|
(1,017
|
)
|
|
(185
|
)
|
||||||
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(99
|
)
|
|
(107
|
)
|
|
8
|
|
|
(199
|
)
|
|
(207
|
)
|
|
8
|
|
||||||
Adjusted EBITDA related to unconsolidated affiliates
|
228
|
|
|
247
|
|
|
(19
|
)
|
|
413
|
|
|
486
|
|
|
(73
|
)
|
||||||
Other, net
|
2
|
|
|
19
|
|
|
(17
|
)
|
|
6
|
|
|
29
|
|
|
(23
|
)
|
||||||
Segment Adjusted EBITDA
|
$
|
2,051
|
|
|
$
|
1,545
|
|
|
$
|
506
|
|
|
$
|
3,932
|
|
|
$
|
2,990
|
|
|
$
|
942
|
|
•
|
an increase of
$60 million
in ETP’s intrastate transportation and storage operations resulting from
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; an increase of
$4 million
in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, due to higher demand on existing pipelines; and
an increase of
$3 million
in realized storage margin primarily due to higher realized derivative gains;
|
•
|
an increase of
$68 million
in ETP’s interstate transportation and storage operations due to an increase of
$68 million
due to the partial in service of the Rover pipeline with increases of
$105 million
in revenues,
$30 million
in operating expenses and
$7 million
in general and administrative expenses; and an increase of
$19 million
in revenues, excluding the incremental revenue from Rover pipeline, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines; partially offset by an increase of
$8 million
in operating expenses, excluding the incremental expenses from Rover pipeline; an increase of
$3 million
in selling, general and administrative expenses, excluding the incremental expenses from Rover pipeline; and decrease of
$5 million
in Adjusted EBITDA related to unconsolidated affiliates due to lower sales of short-term firm capacity on Citrus;
|
•
|
an increase of
$2 million
in ETP’s midstream operations primarily due to an
$8 million
increase in non-fee-based margins mainly due to higher realized crude oil and NGL prices and increased throughput in the Permian region; a
$17 million
increase in fee-based revenues due to increased volumes in the Permian and Northeast regions offset by declines in South Texas, North Texas and the midcontinent/Panhandle regions; and an increase of
$2 million
in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from ETP’s Aqua, Mi Vida and Ranch joint ventures; partially offset by an increase of
$17 million
in operating expenses primarily due to outside services and materials expense; 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
$73 million
in ETP’s NGL and refined products transportation and services operations due to an increase of
$49 million
in transportation volume, primarily due to a
$43 million
increase from higher volumes on ETP’s Texas NGL pipelines, an increase of
$11 million
resulting from reclassification between transportation and fractionation margins, and an increase of
$4 million
due to higher volumes on the Mariner West and Mariner South systems, offset by decrease of
$11 million
due to 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 ETP’s butane blending operations, an increase of
$9 million
from sales of domestic propane from other products at ETP’s Marcus Hook Industrial Complex and an increase of
$4 million
from optimizing sales of purity projects from ETP’s 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 ETP’s Mont Belvieu fractionation facility and a
$6 million
increase from blending gains as a result of improved market pricing, offset by a decrease of
$11 million
resulting from reclassification between ETP’s transportation and fraction margins; and an increase of
$10 million
in terminalling services margin primarily 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; partially offset by an increase of
$16 million
in operating expenses 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
$320 million
in ETP’s crude oil transportation and services operations primarily due to an increase of
$193 million
resulting primarily from placing ETP’s 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 ETP’s 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 ETP’s Nederland facility as a result of increased exports; a decrease of
$12 million
in selling, general and administrative expense 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 ETP’s joint ventures; partially offset by an increase of
$30 million
in operating expenses primarily due to assets recently placed in service, as well as higher expenses on existing assets; partially offset by
|
•
|
a decrease of
$17 million
in ETP’s all other operations due to
a decrease of
$44 million
in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in Sunoco LP resulting from the ETP’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018; 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
|
•
|
an increase of
$83 million
in ETP’s intrastate transportation and storage operations resulting from
an increase of
$105 million
in realized natural gas sales and other margin 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; 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.
|
•
|
an increase of
$126 million
in ETP’s interstate transportation and storage operations due to an increase of
$117 million
due to the partial in service of the Rover pipeline in August 2017 with increases of
$187 million
in revenues,
$56 million
in operating expenses and
$14 million
in general and administrative expenses; and an increase of
$21 million
in revenues, excluding the incremental revenue from Rover pipeline, 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 increase of
$2 million
in operating expenses, excluding the incremental expenses from Rover pipeline; 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;
|
•
|
an increase of
$59 million
in ETP’s midstream operations primarily due to a
$51 million
increase in non-fee-based margins due to higher realized crude oil and NGL prices and increased throughput in the Permian region; a
$30 million
increase in gathering and fee-based revenues due to increased volumes in the Permian and Northeast regions offset by declines in South Texas, North Texas and the 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 primarily due to outside services and materials expense; 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;
|
•
|
an increase of
$143 million
in ETP’s NGL and refined products transportation and services operations due to an increase of
$82 million
in transportation volume, primarily due to
$78 million
increase from higher volumes on ETP’s Texas NGL pipelines, an increase of
$11 million
resulting from reclassification between transportation and fractionation margins and $14 million from higher volumes on the Mariner West and Mariner South systems, partially offset by a
$17 million
decrease resulting from lower throughput on Mariner East 1 due to system downtime in 2018 and
$8 million
due to lower transport revenue from the Eagle Ford and Southeast Texas regions; 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 ETP’s butane blending operations, a
$17 million
increase from sales of domestic propane from other products at ETP’s Marcus Hook Industrial Complex and a
$13 million
increase from optimizing sales of purity products from ETP’s Mont Belvieu fractionators; and 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 ETP’s Mont Belvieu fractionation facility and a
$9 million
increase from blending gains as a result of improved market pricing, offset by a decrease of
$11 million
resulting from reclassification between ETP’s transportation and fraction margins; an increase of
$17 million
in terminalling services margin primarily 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 an increase of
$5 million
in Adjusted EBITDA related to unconsolidated affiliates due to improved contributions from ETP’s unconsolidated refined products joint venture interests; partially offset by an increase of
$28 million
in operating expenses and a decrease in storage margin due to a
$8 million
decrease from the expiration and amendments to various NGL and refined products storage contracts
|
•
|
an increase of
$597 million
in ETP’s crude oil transportation and services operations primarily due to a
$417 million
increase resulting primarily from placing ETP’s 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 ETP’s 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 ETP’s 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 primarily due to a decrease in professional
|
•
|
a decrease of
$66 million
in ETP’s all other operations due to a decrease of
$69 million
in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in Sunoco LP resulting from ETP’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018; a decrease of
$18 million
in Adjusted EBITDA related to unconsolidated affiliates primarily from our investment in PES; 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.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Revenues
|
$
|
4,607
|
|
|
$
|
2,892
|
|
|
$
|
1,715
|
|
|
$
|
8,356
|
|
|
$
|
5,700
|
|
|
$
|
2,656
|
|
Cost of products sold
|
4,297
|
|
|
2,633
|
|
|
1,664
|
|
|
7,750
|
|
|
5,185
|
|
|
2,565
|
|
||||||
Unrealized gains on commodity risk management activities
|
—
|
|
|
5
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Operating expenses, excluding non-cash compensation expense
|
(105
|
)
|
|
(115
|
)
|
|
10
|
|
|
(218
|
)
|
|
(227
|
)
|
|
9
|
|
||||||
Selling, general and administrative, excluding non-cash compensation expense
|
(31
|
)
|
|
(31
|
)
|
|
—
|
|
|
(63
|
)
|
|
(59
|
)
|
|
(4
|
)
|
||||||
Inventory fair value adjustments
|
(32
|
)
|
|
30
|
|
|
(62
|
)
|
|
(57
|
)
|
|
43
|
|
|
(100
|
)
|
||||||
Adjusted EBITDA from discontinued operations
|
(5
|
)
|
|
72
|
|
|
(77
|
)
|
|
(25
|
)
|
|
103
|
|
|
(128
|
)
|
||||||
Other
|
3
|
|
|
—
|
|
|
3
|
|
|
6
|
|
|
—
|
|
|
6
|
|
||||||
Segment Adjusted EBITDA
|
$
|
140
|
|
|
$
|
220
|
|
|
$
|
(80
|
)
|
|
$
|
249
|
|
|
$
|
375
|
|
|
$
|
(126
|
)
|
•
|
a decrease of $77 million in Adjusted EBITDA from discontinued operations primarily attributable to Sunoco LP’s retail divestment in January 2018; offset by
|
•
|
a decrease in other operating expense of
$10 million
primarily due to a decrease in rent expense of $3 million and a decrease in other operating of $7 million primarily due to lower salaries and benefits; and
|
•
|
an increase in fuel distribution and marketing gross profit on motor fuel of a $102 million primarily due to a $62 million favorable change in inventory adjustments, as well as an increase in motor fuel gallons sold, partially offset by a decrease in gross profit of
$51 million
from other motor fuel, merchandise, rental and other due to the conversion of 207 retail sites to commission agent sites during the current period.
|
•
|
a decrease of $128 million in Adjusted EBITDA from discontinued operations primarily attributable to Sunoco LP’s retail divestment in January 2018; offset by
|
•
|
an increase in fuel distribution and marketing gross profits on motor fuel of $140 million primarily due to $100 million favorable change in inventory adjustments, as well as an increase in motor fuel gallons sold, partially offset by a decrease in gross profit of
$49 million
from other motor fuel, merchandise, rental and other due to the conversion of 207 retail sites to commission agent sites during the current period; and
|
•
|
a decrease in other operating expense of
$9 million
primarily due to a net decrease in rent expense of
$8 million
.
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Revenues
|
$
|
167
|
|
|
$
|
—
|
|
|
$
|
167
|
|
|
$
|
167
|
|
|
$
|
—
|
|
|
$
|
167
|
|
Cost of products sold
|
20
|
|
|
—
|
|
|
20
|
|
|
20
|
|
|
—
|
|
|
20
|
|
||||||
Operating expenses, excluding non-cash compensation expense
|
(38
|
)
|
|
—
|
|
|
(38
|
)
|
|
(38
|
)
|
|
—
|
|
|
(38
|
)
|
||||||
Selling, general and administrative, excluding non-cash compensation expense
|
(19
|
)
|
|
—
|
|
|
(19
|
)
|
|
(19
|
)
|
|
—
|
|
|
(19
|
)
|
||||||
Other
|
5
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|
—
|
|
|
5
|
|
||||||
Segment Adjusted EBITDA
|
$
|
95
|
|
|
$
|
—
|
|
|
$
|
95
|
|
|
$
|
95
|
|
|
$
|
—
|
|
|
$
|
95
|
|
|
Three Months Ended
June 30, |
|
|
|
Six Months Ended
June 30, |
|
|
||||||||||||||||
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
||||||||||||
Revenues
|
$
|
49
|
|
|
$
|
50
|
|
|
$
|
(1
|
)
|
|
$
|
98
|
|
|
$
|
99
|
|
|
$
|
(1
|
)
|
Operating expenses, excluding non-cash compensation expense
|
(4
|
)
|
|
(4
|
)
|
|
—
|
|
|
(9
|
)
|
|
(9
|
)
|
|
—
|
|
||||||
Selling, general and administrative, excluding non-cash compensation expense
|
—
|
|
|
(2
|
)
|
|
2
|
|
|
(1
|
)
|
|
(2
|
)
|
|
1
|
|
||||||
Segment Adjusted EBITDA
|
$
|
45
|
|
|
$
|
44
|
|
|
$
|
1
|
|
|
$
|
88
|
|
|
$
|
88
|
|
|
$
|
—
|
|
|
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 ETP’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.
|
•
|
maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of its assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining its existing business and related operating income; and
|
•
|
expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that were not currently generating operating income.
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Parent Company Indebtedness:
|
|
|
|
||||
ETE Senior Notes due October 2020
|
$
|
1,187
|
|
|
$
|
1,187
|
|
ETE Senior Notes due March 2023
|
1,000
|
|
|
1,000
|
|
||
ETE Senior Notes due January 2024
|
1,150
|
|
|
1,150
|
|
||
ETE Senior Notes due June 2027
|
1,000
|
|
|
1,000
|
|
||
ETE Senior Secured Term Loan due February 2, 2024
|
1,220
|
|
|
1,220
|
|
||
ETE Senior Secured Revolving Credit Facility due March 24, 2022
|
956
|
|
|
1,188
|
|
||
Subsidiary Indebtedness:
|
|
|
|
||||
ETP Senior Notes
(1)(2)
|
29,354
|
|
|
27,005
|
|
||
Transwestern Senior Notes
|
575
|
|
|
575
|
|
||
Panhandle Senior Notes
|
386
|
|
|
785
|
|
||
Sunoco LP Senior Notes, Term Loan and lease-related obligation
|
2,312
|
|
|
3,556
|
|
||
USAC Senior Notes
|
725
|
|
|
—
|
|
||
Credit Facilities and Commercial Paper:
|
|
|
|
||||
ETP $4.0 billion Revolving Credit Facility due December 2022
(3)
|
1,228
|
|
|
2,292
|
|
||
ETP $1.0 billion 364-Day Credit Facility due November 2018
|
—
|
|
|
50
|
|
||
Bakken Project $2.50 billion Credit Facility due August 2019
|
2,500
|
|
|
2,500
|
|
||
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019
|
320
|
|
|
765
|
|
||
USAC $1.6 billion Revolving Credit Facility due April 2023
|
950
|
|
|
—
|
|
||
Other Long-Term Debt
|
6
|
|
|
8
|
|
||
Unamortized premiums and fair value adjustments, net
|
28
|
|
|
50
|
|
||
Deferred debt issuance costs
|
(264
|
)
|
|
(247
|
)
|
||
Total
|
44,633
|
|
|
44,084
|
|
||
Less: Current maturities of long-term debt
|
160
|
|
|
413
|
|
||
Long-term debt and notes payable, less current maturities
|
$
|
44,473
|
|
|
$
|
43,671
|
|
(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.
|
(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.
|
•
|
redeem in full its existing senior notes, comprised of
$800 million
in aggregate principal amount of
6.250%
senior notes due 2021,
$600 million
in aggregate principal amount of
5.500%
senior notes due 2020, and
$800 million
in aggregate principal amount of
6.375%
senior notes due 2023;
|
•
|
repay in full and terminate its term loan;
|
•
|
pay all closing costs in connection with the 7-Eleven transaction;
|
•
|
redeem the outstanding Sunoco LP Series A Preferred Units; and
|
•
|
repurchase
17,286,859
common units owned by ETP.
|
•
|
$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 (1)
|
|
February 8, 2018
|
|
February 20, 2018
|
|
$
|
0.3050
|
|
March 31, 2018 (1)
|
|
May 7, 2018
|
|
May 21, 2018
|
|
0.3050
|
|
|
June 30, 2018
|
|
August 6, 2018
|
|
August 20, 2018
|
|
0.3050
|
|
(1)
|
Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forgo their cash distributions on all or a portion of their common units, and in lieu of receiving cash distributions on these common units for each such quarter, such unitholder received Series A Convertible Preferred Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to
$0.11
per Series A Convertible Preferred Unit. The quarter ended March 31, 2018 was the final quarter of participation in the plan.
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2017
|
|
February 8, 2018
|
|
February 20, 2018
|
|
$
|
0.1100
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 21, 2018
|
|
0.1100
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Limited Partners
|
$
|
618
|
|
|
$
|
500
|
|
General Partner interest
|
2
|
|
|
2
|
|
||
Total Parent Company distributions
|
$
|
620
|
|
|
$
|
502
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Distributions from ETP:
|
|
|
|
||||
Limited Partner interests
|
$
|
31
|
|
|
$
|
30
|
|
General partner interest and IDRs
|
900
|
|
|
781
|
|
||
IDR relinquishments net of Class I Unit distributions
|
(84
|
)
|
|
(319
|
)
|
||
Total distributions from ETP
|
847
|
|
|
492
|
|
||
Distributions from Sunoco LP
|
|
|
|
||||
Limited Partner interests
|
4
|
|
|
4
|
|
||
IDRs
|
35
|
|
|
42
|
|
||
Series A Preferred
|
—
|
|
|
8
|
|
||
Total distributions from Sunoco LP
|
39
|
|
|
54
|
|
||
Distributions from USAC
|
|
|
|
||||
Limited Partner interests
|
11
|
|
|
—
|
|
||
Total distributions from USAC
|
11
|
|
|
—
|
|
||
Total distributions received from subsidiaries
|
$
|
897
|
|
|
$
|
546
|
|
|
|
Year Ending December 31,
|
||
2018 (remainder)
|
|
$
|
69
|
|
2019
|
|
128
|
|
|
Each year beyond 2019
|
|
33
|
|
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
|
||
ETP 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
|
|
|
ETP 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
|
|
|
ETP 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
|
)
|
||
ETP Series A Preferred Units
|
30
|
|
|
—
|
|
||
ETP Series B Preferred Units
|
18
|
|
|
—
|
|
||
ETP Series C Preferred Units
|
10
|
|
|
—
|
|
||
Total distributions declared to partners
|
$
|
2,191
|
|
|
$
|
1,648
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
December 31, 2017
|
|
February 6, 2018
|
|
February 14, 2018
|
|
$
|
0.8255
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 15, 2018
|
|
0.8255
|
|
|
June 30, 2018
|
|
August 7, 2018
|
|
August 15, 2018
|
|
0.8255
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Limited Partners:
|
|
|
|
||||
Common units held by public
|
$
|
89
|
|
|
$
|
89
|
|
Common and subordinated units held by ETP
|
43
|
|
|
100
|
|
||
Common and subordinated units held by ETE
|
4
|
|
|
4
|
|
||
General Partner interest and incentive distributions
|
35
|
|
|
42
|
|
||
Series A Preferred
|
—
|
|
|
8
|
|
||
Total distributions declared
|
$
|
171
|
|
|
$
|
243
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
||
March 31, 2018
|
|
May 1, 2018
|
|
May 11, 2018
|
|
$
|
0.5250
|
|
June 30, 2018
|
|
July 30, 2018
|
|
August 10, 2018
|
|
0.5250
|
|
|
Six Months Ended
June 30, |
||
|
2018
|
||
Limited Partners:
|
|
||
Common units held by public and other
|
$
|
63
|
|
Common units held by ETP
|
20
|
|
|
Common held by ETE
|
11
|
|
|
Total distributions declared
|
$
|
94
|
|
|
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
|
|
|
4
|
|
|
—
|
|
|
48,510
|
|
|
2
|
|
|
1
|
|
||||
Options – Puts
|
(3,043
|
)
|
|
—
|
|
|
—
|
|
|
13,000
|
|
|
—
|
|
|
—
|
|
||||
Options – Calls
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
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
|
|
|
(51
|
)
|
|
18
|
|
|
4,650
|
|
|
(13
|
)
|
|
4
|
|
||||
Swing Swaps IFERC
|
52,413
|
|
|
(1
|
)
|
|
—
|
|
|
87,253
|
|
|
(2
|
)
|
|
1
|
|
||||
Fixed Swaps/Futures
|
5,460
|
|
|
(2
|
)
|
|
3
|
|
|
(4,390
|
)
|
|
(1
|
)
|
|
2
|
|
||||
Forward Physical Contracts
|
(174,465
|
)
|
|
4
|
|
|
—
|
|
|
(145,105
|
)
|
|
6
|
|
|
41
|
|
||||
NGL (MBbls) – Forwards/Swaps
|
(1,590
|
)
|
|
(18
|
)
|
|
11
|
|
|
(2,493
|
)
|
|
5
|
|
|
16
|
|
||||
Crude (MBbls) – Forwards/Swaps
|
44,335
|
|
|
(307
|
)
|
|
261
|
|
|
9,237
|
|
|
(4
|
)
|
|
9
|
|
||||
Refined Products (MBbls) – Futures
|
(776
|
)
|
|
(6
|
)
|
|
6
|
|
|
(3,901
|
)
|
|
(27
|
)
|
|
4
|
|
||||
Corn (thousand bushels)
|
(3,320
|
)
|
|
1
|
|
|
—
|
|
|
1,870
|
|
|
—
|
|
|
—
|
|
||||
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.
|
|
|
|
|
Notional Amount Outstanding
|
||||||
Term
|
|
Type
(1)
|
|
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 a term of 30 years with a mandatory termination date the same as the effective date.
|
•
|
interest expense and principal payments on our indebtedness;
|
•
|
restrictions on distributions contained in any current or future debt agreements;
|
•
|
our general and administrative expenses;
|
•
|
expenses of our subsidiaries other than ETP, Sunoco LP and USAC, including tax liabilities of our corporate subsidiaries, if any; and
|
•
|
reserves our General Partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.
|
•
|
the amount of natural gas, NGLs, crude oil and refined products transported through ETP’s pipelines and gathering systems;
|
•
|
the level of throughput in processing and treating operations;
|
•
|
the fees charged and the margins realized by ETP, Sunoco LP and USAC for their services;
|
•
|
the price of natural gas, NGLs, crude oil and refined products;
|
•
|
the relationship between natural gas, NGL and crude oil prices;
|
•
|
the amount of cash distributions ETP receives with respect to the Sunoco LP common units and USAC common units that ETP or its subsidiaries own;
|
•
|
the weather in their respective operating areas;
|
•
|
the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;
|
•
|
the level of their respective operating costs and maintenance and integrity capital expenditures;
|
•
|
the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;
|
•
|
prevailing economic conditions; and
|
•
|
the level and results of their respective derivative activities.
|
•
|
the level of capital expenditures they make;
|
•
|
the level of costs related to litigation and regulatory compliance matters;
|
•
|
the cost of acquisitions, if any;
|
•
|
the levels of any margin calls that result from changes in commodity prices;
|
•
|
debt service requirements;
|
•
|
fluctuations in working capital needs;
|
•
|
their ability to borrow under their respective revolving credit facilities;
|
•
|
their ability to access capital markets;
|
•
|
restrictions on distributions contained in their respective debt agreements; and
|
•
|
the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.
|
•
|
Unitholders’ current proportionate ownership interest in each partnership will decrease;
|
•
|
the amount of cash available for distribution on each common unit or partnership security may decrease;
|
•
|
the ratio of taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding common unit may be diminished; and
|
•
|
the market price of each partnership’s common units may decline.
|
•
|
a significant portion of ETP’s, Sunoco LP’s and USAC’s and their subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;
|
•
|
covenants contained in ETP’s, Sunoco LP’s and USAC’s and their subsidiaries’ existing debt agreements require ETP, Sunoco LP, USAC and their subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;
|
•
|
ETP’s, Sunoco LP’s and USAC’s and their subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
|
•
|
ETP, Sunoco LP and USAC may be at a competitive disadvantage relative to similar companies that have less debt;
|
•
|
ETP, Sunoco LP and USAC may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels;
|
•
|
failure by ETP, Sunoco LP, USAC or their subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETP’s, Sunoco LP’s and USAC’s ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions to us and their unitholders.
|
•
|
the allocation of shared overhead expenses to ETP, Sunoco LP, USAC and us;
|
•
|
the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP, Sunoco LP and USAC, on the other hand;
|
•
|
the determination of the amount of cash to be distributed to ETP’s, Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of ETP’s, Sunoco LP’s and USAC’s businesses;
|
•
|
the determination whether to make borrowings under ETP’s, Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners;
|
•
|
the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of ETP, Sunoco LP and USAC is made available for ETP, Sunoco LP and USAC to pursue; and
|
•
|
any decision we make in the future to engage in business activities independent of ETP, Sunoco LP and USAC.
|
•
|
inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
|
•
|
inability to raise financing for such acquisitions on economically acceptable terms; or
|
•
|
inability to outbid by competitors, some of which are substantially larger than ETP, Sunoco LP or USAC and may have greater financial resources and lower costs of capital.
|
•
|
fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
|
•
|
decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;
|
•
|
significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;
|
•
|
encounter difficulties operating in new geographic areas or new lines of business;
|
•
|
incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which there is no indemnity or the indemnity is inadequate;
|
•
|
be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;
|
•
|
less effectively manage its historical assets, due to the diversion of management’s attention from other business concerns; or
|
•
|
incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
|
•
|
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
|
•
|
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
|
|
Description
|
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document
|
101.CAL*
|
|
XBRL Taxonomy Calculation Linkbase Document
|
101.DEF*
|
|
XBRL Taxonomy Extension Definitions Document
|
101.LAB*
|
|
XBRL Taxonomy Label Linkbase Document
|
101.PRE*
|
|
XBRL Taxonomy Presentation Linkbase Document
|
*
|
|
Filed herewith.
|
**
|
|
Furnished herewith.
|
***
|
|
Denotes a management contract or compensatory plan or arrangement. Filed herewith.
|
|
|
ENERGY TRANSFER EQUITY, L.P.
|
||
|
|
|
|
|
|
|
By:
|
|
LE GP, LLC, its General Partner
|
|
|
|
|
|
Date:
|
August 9, 2018
|
By:
|
|
/s/ Thomas E. Long
|
|
|
|
|
Thomas E. Long
|
|
|
|
|
Group Chief Financial Officer (duly
authorized to sign on behalf of the registrant)
|
1 Year Energy Transfer Equity Chart |
1 Month Energy Transfer Equity Chart |
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