ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 73-1493906 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
Large accelerated filer | ý | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ | |||
Emerging growth company | ¨ |
/d | per day | ||
AOCI | accumulated other comprehensive income (loss) | ||
BBtu | billion British thermal units | ||
Btu | British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used | ||
Capacity | capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels | ||
CDM | CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively | ||
Citrus | Citrus, LLC | ||
DOJ | United States Department of Justice | ||
EPA | United States Environmental Protection Agency | ||
ETC OLP | La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company | ||
ETE | Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC for the periods presented herein | ||
ETP GP | Energy Transfer Partners GP, L.P., the general partner of ETP | ||
ETP Holdco | ETP Holdco Corporation | ||
ETP LLC | Energy Transfer Partners, L.L.C., the general partner of ETP GP | ||
Exchange Act | Securities Exchange Act of 1934 | ||
FEP | Fayetteville Express Pipeline LLC | ||
FERC | Federal Energy Regulatory Commission | ||
FGT | Florida Gas Transmission Company, LLC | ||
GAAP | accounting principles generally accepted in the United States of America | ||
HPC | RIGS Haynesville Partnership Co. | ||
IDRs | incentive distribution rights | ||
Legacy ETP Preferred Units | legacy ETP Series A cumulative convertible preferred units | ||
LIBOR | London Interbank Offered Rate | ||
MBbls | thousand barrels | ||
MEP | Midcontinent Express Pipeline LLC | ||
MTBE | methyl tertiary butyl ether | ||
NGL | natural gas liquid, such as propane, butane and natural gasoline | ||
NYMEX | New York Mercantile Exchange | ||
OSHA | federal Occupational Safety and Health Act | ||
OTC | over-the-counter | ||
Panhandle | Panhandle Eastern Pipe Line Company, LP and its subsidiaries | ||
PennTex | PennTex Midstream Partners, LP | ||
PES | Philadelphia Energy Solutions | ||
Regency | Regency Energy Partners LP | ||
Retail Holdings | ETP Retail Holdings, LLC, a wholly-owned subsidiary of Sunoco, Inc. | ||
RIGS | Regency Intrastate Gas LP | ||
Rover | Rover Pipeline LLC, a subsidiary of ETP | ||
SEC | Securities and Exchange Commission | ||
Series A Preferred Units | 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Series B Preferred Units | 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Series C Preferred Units | 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Series D Preferred Units | 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Sunoco Logistics | Sunoco Logistics Partners L.P. | ||
Transwestern | Transwestern Pipeline Company, LLC | ||
Trunkline | Trunkline Gas Company, LLC, a subsidiary of Panhandle | ||
USAC | USA Compression Partners, LP |
June 30, 2018 | December 31, 2017 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 494 | $ | 306 | |||
Accounts receivable, net | 3,684 | 3,946 | |||||
Accounts receivable from related companies | 334 | 318 | |||||
Inventories | 1,256 | 1,589 | |||||
Income taxes receivable | 172 | 135 | |||||
Derivative assets | 57 | 24 | |||||
Other current assets | 550 | 210 | |||||
Total current assets | 6,547 | 6,528 | |||||
Property, plant and equipment | 69,637 | 67,699 | |||||
Accumulated depreciation and depletion | (9,861 | ) | (9,262 | ) | |||
59,776 | 58,437 | ||||||
Advances to and investments in unconsolidated affiliates | 3,636 | 3,816 | |||||
Other non-current assets, net | 762 | 758 | |||||
Intangible assets, net | 4,988 | 5,311 | |||||
Goodwill | 2,861 | 3,115 | |||||
Total assets | $ | 78,570 | $ | 77,965 |
June 30, 2018 | December 31, 2017 | ||||||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 3,488 | $ | 4,126 | |||
Accounts payable to related companies | 329 | 209 | |||||
Derivative liabilities | 385 | 109 | |||||
Accrued and other current liabilities | 2,284 | 2,143 | |||||
Current maturities of long-term debt | 155 | 407 | |||||
Total current liabilities | 6,641 | 6,994 | |||||
Long-term debt, less current maturities | 33,741 | 32,687 | |||||
Non-current derivative liabilities | 135 | 145 | |||||
Deferred income taxes | 2,917 | 2,883 | |||||
Other non-current liabilities | 1,079 | 1,084 | |||||
Commitments and contingencies | |||||||
Redeemable noncontrolling interests | 21 | 21 | |||||
Equity: | |||||||
Limited Partners: | |||||||
Series A Preferred Unitholders | 958 | 944 | |||||
Series B Preferred Unitholders | 556 | 547 | |||||
Series C Preferred Unitholders | 442 | — | |||||
Common Unitholders | 25,546 | 26,531 | |||||
General Partner | 359 | 244 | |||||
Accumulated other comprehensive income | 4 | 3 | |||||
Total partners’ capital | 27,865 | 28,269 | |||||
Noncontrolling interest | 6,171 | 5,882 | |||||
Total equity | 34,036 | 34,151 | |||||
Total liabilities and equity | $ | 78,570 | $ | 77,965 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017* | 2018 | 2017* | ||||||||||||
REVENUES: | |||||||||||||||
Natural gas sales | $ | 1,024 | $ | 1,022 | $ | 2,086 | $ | 2,034 | |||||||
NGL sales | 2,141 | 1,485 | 4,171 | 3,032 | |||||||||||
Crude sales | 4,241 | 2,345 | 7,495 | 4,887 | |||||||||||
Gathering, transportation and other fees | 1,464 | 1,067 | 2,861 | 2,091 | |||||||||||
Refined product sales | 413 | 304 | 852 | 775 | |||||||||||
Other | 127 | 353 | 225 | 652 | |||||||||||
Total revenues | 9,410 | 6,576 | 17,690 | 13,471 | |||||||||||
COSTS AND EXPENSES: | |||||||||||||||
Cost of products sold | 7,140 | 4,624 | 13,128 | 9,674 | |||||||||||
Operating expenses | 627 | 539 | 1,231 | 1,031 | |||||||||||
Depreciation, depletion and amortization | 588 | 557 | 1,191 | 1,117 | |||||||||||
Selling, general and administrative | 112 | 120 | 224 | 230 | |||||||||||
Total costs and expenses | 8,467 | 5,840 | 15,774 | 12,052 | |||||||||||
OPERATING INCOME | 943 | 736 | 1,916 | 1,419 | |||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||
Interest expense, net | (358 | ) | (336 | ) | (704 | ) | (668 | ) | |||||||
Equity in earnings (losses) of unconsolidated affiliates | 106 | (61 | ) | 34 | 12 | ||||||||||
Gain on Sunoco LP common unit repurchase | — | — | 172 | — | |||||||||||
Loss on deconsolidation of CDM | (86 | ) | — | (86 | ) | — | |||||||||
Gains (losses) on interest rate derivatives | 20 | (25 | ) | 72 | (20 | ) | |||||||||
Other, net | 46 | 61 | 106 | 80 | |||||||||||
INCOME BEFORE INCOME TAX EXPENSE | 671 | 375 | 1,510 | 823 | |||||||||||
Income tax expense | 69 | 79 | 29 | 134 | |||||||||||
NET INCOME | 602 | 296 | 1,481 | 689 | |||||||||||
Less: Net income attributable to noncontrolling interest | 170 | 94 | 334 | 156 | |||||||||||
NET INCOME ATTRIBUTABLE TO PARTNERS | 432 | 202 | 1,147 | 533 | |||||||||||
Series A Preferred Unitholders’ interest in net income | 15 | — | 30 | — | |||||||||||
Series B Preferred Unitholders’ interest in net income | 9 | — | 18 | — | |||||||||||
Series C Preferred Unitholders’ interest in net income | 6 | — | 6 | — | |||||||||||
General Partner’s interest in net income | 402 | 251 | 804 | 457 | |||||||||||
Class H Unitholder’s interest in net income | — | — | — | 93 | |||||||||||
Common Unitholders’ interest in net income (loss) | $ | — | $ | (49 | ) | $ | 289 | $ | (17 | ) | |||||
NET INCOME (LOSS) PER COMMON UNIT: | |||||||||||||||
Basic | $ | (0.01 | ) | $ | (0.04 | ) | $ | 0.23 | $ | (0.02 | ) | ||||
Diluted | $ | (0.01 | ) | $ | (0.04 | ) | $ | 0.23 | $ | (0.02 | ) |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017* | 2018 | 2017* | ||||||||||||
Net income | $ | 602 | $ | 296 | $ | 1,481 | 689 | ||||||||
Other comprehensive income (loss), net of tax: | |||||||||||||||
Change in value of available-for-sale securities | — | 1 | (2 | ) | 3 | ||||||||||
Actuarial loss relating to pension and other postretirement benefit plans | — | (1 | ) | (2 | ) | (3 | ) | ||||||||
Change in other comprehensive income from unconsolidated affiliates | 2 | (1 | ) | 7 | (1 | ) | |||||||||
2 | (1 | ) | 3 | (1 | ) | ||||||||||
Comprehensive income | 604 | 295 | 1,484 | 688 | |||||||||||
Less: Comprehensive income attributable to noncontrolling interest | 170 | 94 | 334 | 156 | |||||||||||
Comprehensive income attributable to partners | $ | 434 | $ | 201 | $ | 1,150 | $ | 532 |
Limited Partners | |||||||||||||||||||||||||||||||
Series A Preferred Units | Series B Preferred Units | Series C Preferred Units | Common Units | General Partner | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interest | Total | ||||||||||||||||||||||||
Balance, December 31, 2017 | $ | 944 | $ | 547 | $ | — | $ | 26,531 | $ | 244 | $ | 3 | $ | 5,882 | $ | 34,151 | |||||||||||||||
Distributions to partners | (15 | ) | (9 | ) | — | (1,315 | ) | (672 | ) | — | — | (2,011 | ) | ||||||||||||||||||
Distributions to noncontrolling interest | — | — | — | — | — | — | (359 | ) | (359 | ) | |||||||||||||||||||||
Units issued for cash | — | — | 436 | 39 | — | — | — | 475 | |||||||||||||||||||||||
Capital contributions from noncontrolling interest | — | — | — | — | — | — | 318 | 318 | |||||||||||||||||||||||
Repurchases of common units | — | — | — | (24 | ) | — | — | — | (24 | ) | |||||||||||||||||||||
Other comprehensive income, net of tax | — | — | — | — | — | 3 | — | 3 | |||||||||||||||||||||||
Other, net | (1 | ) | — | — | 26 | (17 | ) | (2 | ) | (4 | ) | 2 | |||||||||||||||||||
Net income | 30 | 18 | 6 | 289 | 804 | — | 334 | 1,481 | |||||||||||||||||||||||
Balance, June 30, 2018 | $ | 958 | $ | 556 | $ | 442 | $ | 25,546 | $ | 359 | $ | 4 | $ | 6,171 | $ | 34,036 |
Six Months Ended June 30, | |||||||
2018 | 2017* | ||||||
OPERATING ACTIVITIES | |||||||
Net income | $ | 1,481 | $ | 689 | |||
Reconciliation of net income to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 1,191 | 1,117 | |||||
Deferred income taxes | 52 | 121 | |||||
Non-cash compensation expense | 41 | 38 | |||||
Gain on Sunoco LP common unit repurchase | (172 | ) | — | ||||
Loss on deconsolidation of CDM | 86 | — | |||||
Distributions on unvested awards | (17 | ) | (15 | ) | |||
Equity in earnings of unconsolidated affiliates | (34 | ) | (12 | ) | |||
Distributions from unconsolidated affiliates | 215 | 197 | |||||
Other non-cash | (122 | ) | (98 | ) | |||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | 229 | (387 | ) | ||||
Net cash provided by operating activities | 2,950 | 1,650 | |||||
INVESTING ACTIVITIES | |||||||
Cash proceeds from CDM contribution | 1,227 | — | |||||
Cash proceeds from Sunoco LP common unit repurchase | 540 | — | |||||
Cash proceeds from Bakken pipeline transaction | — | 2,000 | |||||
Cash paid for acquisition of PennTex noncontrolling interest | — | (280 | ) | ||||
Cash paid for all other acquisitions | (29 | ) | (261 | ) | |||
Capital expenditures, excluding allowance for equity funds used during construction | (3,409 | ) | (2,842 | ) | |||
Contributions in aid of construction costs | 60 | 10 | |||||
Contributions to unconsolidated affiliates | (13 | ) | (225 | ) | |||
Distributions from unconsolidated affiliates in excess of cumulative earnings | 31 | 94 | |||||
Proceeds from the sale of assets | 2 | 25 | |||||
Other | — | (7 | ) | ||||
Net cash used in investing activities | (1,591 | ) | (1,486 | ) | |||
FINANCING ACTIVITIES | |||||||
Proceeds from borrowings | 12,476 | 11,466 | |||||
Repayments of debt | (12,018 | ) | (10,953 | ) | |||
Cash paid to affiliate notes | — | (255 | ) | ||||
Common units issued for cash | 39 | 990 | |||||
Preferred units issued for cash | 436 | — | |||||
Capital contributions from noncontrolling interest | 318 | 456 | |||||
Distributions to partners | (2,011 | ) | (1,702 | ) | |||
Distributions to noncontrolling interest | (359 | ) | (186 | ) | |||
Repurchases of common units | (24 | ) | — | ||||
Redemption of Legacy ETP Preferred Units | — | (53 | ) | ||||
Debt issuance costs | (38 | ) | (20 | ) | |||
Other | 10 | 5 | |||||
Net cash used in financing activities | (1,171 | ) | (252 | ) | |||
Increase (decrease) in cash and cash equivalents | 188 | (88 | ) | ||||
Cash and cash equivalents, beginning of period | 306 | 360 | |||||
Cash and cash equivalents, end of period | $ | 494 | $ | 272 |
1. | ORGANIZATION AND BASIS OF PRESENTATION |
• | ETC OLP, Regency and PennTex, which are primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP and Regency own and operate, through their wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, West Virginia, Colorado and Ohio. |
• | Energy Transfer Interstate Holdings, LLC, (“ETIH”) with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which is the parent company of: |
• | Transwestern, engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales. |
• | ETC Fayetteville Express Pipeline, LLC, which directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline. |
• | ETC Tiger Pipeline, LLC, engaged in interstate transportation of natural gas. |
• | CrossCountry Energy, LLC, which indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline. |
• | ETC Midcontinent Express Pipeline, L.L.C., which directly owns a 50% interest in MEP. |
• | ET Rover Pipeline, LLC, which ETIH directly owns a 50.1% interest in, which owns a 65% interest in the Rover pipeline. |
• | ETC Compression, LLC, engaged in natural gas compression services and related equipment sales. As discussed further in Note 2 below, in April 2018, we contributed certain assets to USAC. |
• | ETP Holdco, which indirectly owns Panhandle and Sunoco, Inc. Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. Sunoco Inc.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. ETP Holdco also holds an equity method investment in ETP through its ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in ETP’s consolidated financial statements. |
• | Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products. |
Three Months Ended June 30, 2017 | Six Months Ended June 30, 2017 | ||||||||||||||||||||||
As Originally Reported | Effect of Change | As Adjusted | As Originally Reported | Effect of Change | As Adjusted | ||||||||||||||||||
Cost of products sold (1) | $ | 4,628 | $ | (4 | ) | $ | 4,624 | $ | 9,707 | $ | (33 | ) | $ | 9,674 | |||||||||
Operating income | 732 | 4 | 736 | 1,386 | 33 | 1,419 | |||||||||||||||||
Income before income tax expense | 371 | 4 | 375 | 790 | 33 | 823 | |||||||||||||||||
Net income | 292 | 4 | 296 | 656 | 33 | 689 | |||||||||||||||||
Net income attributable to partners | 199 | 3 | 202 | 523 | 10 | 533 | |||||||||||||||||
Net loss per common unit – basic | (0.04 | ) | — | (0.04 | ) | (0.04 | ) | 0.02 | (0.02 | ) | |||||||||||||
Net loss per common unit – diluted | (0.04 | ) | — | (0.04 | ) | (0.04 | ) | 0.02 | (0.02 | ) | |||||||||||||
Comprehensive income | 291 | 4 | 295 | 655 | 33 | 688 | |||||||||||||||||
Comprehensive income attributable to partners | 198 | 3 | 201 | 522 | 10 | 532 |
Six Months Ended June 30, 2017 | |||||||||||
As Originally Reported | Effect of Change | As Adjusted | |||||||||
Net income | $ | 656 | $ | 33 | $ | 689 | |||||
Inventory valuation adjustments | 56 | (56 | ) | — | |||||||
Net change in operating assets and liabilities, net of effects from acquisitions (change in inventories) | (410 | ) | 23 | (387 | ) |
Three Months Ended June 30, 2018 | Six Months Ended June 30, 2018 | ||||||||||||||||||||||
As Reported | Balances Without Adoption of ASC 606 | Effect of Change: Higher/(Lower) | As Reported | Balances Without Adoption of ASC 606 | Effect of Change: Higher/(Lower) | ||||||||||||||||||
Revenues: | |||||||||||||||||||||||
Natural gas sales | $ | 1,024 | $ | 1,024 | $ | — | $ | 2,086 | $ | 2,086 | $ | — | |||||||||||
NGL sales | 2,141 | 2,134 | 7 | 4,171 | 4,153 | 18 | |||||||||||||||||
Crude sales | 4,241 | 4,238 | 3 | 7,495 | 7,488 | 7 | |||||||||||||||||
Gathering, transportation and other fees | 1,464 | 1,611 | (147 | ) | 2,861 | 3,194 | (333 | ) | |||||||||||||||
Refined product sales | 413 | 413 | — | 852 | 852 | — | |||||||||||||||||
Other | 127 | 127 | — | 225 | 225 | — | |||||||||||||||||
Costs and expenses: | |||||||||||||||||||||||
Cost of products sold | $ | 7,140 | $ | 7,287 | $ | (147 | ) | $ | 13,128 | $ | 13,461 | $ | (333 | ) | |||||||||
Operating expenses | 627 | 617 | 10 | 1,231 | 1,206 | 25 |
2. | ACQUISITIONS AND OTHER INVESTING TRANSACTIONS |
3. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES |
4. | CASH AND CASH EQUIVALENTS |
Six Months Ended June 30, | |||||||
2018 | 2017* | ||||||
Accounts receivable | $ | 236 | $ | 88 | |||
Accounts receivable from related companies | 156 | (115 | ) | ||||
Inventories | 299 | 160 | |||||
Other current assets | (375 | ) | 77 | ||||
Other non-current assets, net | (3 | ) | (39 | ) | |||
Accounts payable | (465 | ) | (286 | ) | |||
Accounts payable to related companies | (99 | ) | 131 | ||||
Accrued and other current liabilities | 249 | (389 | ) | ||||
Other non-current liabilities | (2 | ) | 7 | ||||
Derivative assets and liabilities, net | 233 | (21 | ) | ||||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | 229 | $ | (387 | ) |
Six Months Ended June 30, | |||||||
2018 | 2017 | ||||||
NON-CASH INVESTING ACTIVITIES: | |||||||
Accrued capital expenditures | $ | 1,007 | $ | 1,363 | |||
USAC limited partner interests received in the CDM Contribution (see Note 2) | 411 | — | |||||
NON-CASH FINANCING ACTIVITIES: | |||||||
Contribution of property, plant and equipment from noncontrolling interest | $ | — | $ | 988 |
5. | INVENTORIES |
June 30, 2018 | December 31, 2017 | ||||||
Natural gas, NGLs and refined products | $ | 434 | $ | 733 | |||
Crude oil | 571 | 551 | |||||
Spare parts and other | 251 | 305 | |||||
Total inventories | $ | 1,256 | $ | 1,589 |
6. | FAIR VALUE MEASURES |
Fair Value Measurements at June 30, 2018 | |||||||||||
Fair Value Total | Level 1 | Level 2 | |||||||||
Assets: | |||||||||||
Commodity derivatives: | |||||||||||
Natural Gas: | |||||||||||
Basis Swaps IFERC/NYMEX | $ | 22 | $ | 22 | $ | — | |||||
Swing Swaps IFERC | 1 | — | 1 | ||||||||
Fixed Swaps/Futures | 11 | 11 | — | ||||||||
Forward Physical Contracts | 9 | — | 9 | ||||||||
Power: | |||||||||||
Forwards | 69 | — | 69 | ||||||||
Options – Puts | 1 | 1 | — | ||||||||
NGLs – Forwards/Swaps | 300 | 300 | — | ||||||||
Total commodity derivatives | 413 | 334 | 79 | ||||||||
Other non-current assets | 21 | 14 | 7 | ||||||||
Total assets | $ | 434 | $ | 348 | $ | 86 | |||||
Liabilities: | |||||||||||
Interest rate derivatives | $ | (147 | ) | $ | — | $ | (147 | ) | |||
Commodity derivatives: | |||||||||||
Natural Gas: | |||||||||||
Basis Swaps IFERC/NYMEX | (70 | ) | (70 | ) | — | ||||||
Swing Swaps IFERC | (2 | ) | (1 | ) | (1 | ) | |||||
Fixed Swaps/Futures | (14 | ) | (14 | ) | — | ||||||
Forward Physical Contracts | (5 | ) | — | (5 | ) | ||||||
Power – Forwards | (57 | ) | — | (57 | ) | ||||||
NGLs – Forwards/Swaps | (316 | ) | (316 | ) | — | ||||||
Refined Products – Futures | (5 | ) | (5 | ) | — | ||||||
Crude – Forwards/Swaps | (307 | ) | (307 | ) | — | ||||||
Total commodity derivatives | (776 | ) | (713 | ) | (63 | ) | |||||
Total liabilities | $ | (923 | ) | $ | (713 | ) | $ | (210 | ) |
Fair Value Measurements at December 31, 2017 | |||||||||||
Fair Value Total | Level 1 | Level 2 | |||||||||
Assets: | |||||||||||
Commodity derivatives: | |||||||||||
Natural Gas: | |||||||||||
Basis Swaps IFERC/NYMEX | $ | 11 | $ | 11 | $ | — | |||||
Swing Swaps IFERC | 13 | — | 13 | ||||||||
Fixed Swaps/Futures | 70 | 70 | — | ||||||||
Forward Physical Swaps | 8 | — | 8 | ||||||||
Power – Forwards | 23 | — | 23 | ||||||||
NGLs – Forwards/Swaps | 191 | 191 | — | ||||||||
Crude: | |||||||||||
Forwards/Swaps | 2 | 2 | — | ||||||||
Futures | 2 | 2 | — | ||||||||
Total commodity derivatives | 320 | 276 | 44 | ||||||||
Other non-current assets | 21 | 14 | 7 | ||||||||
Total assets | $ | 341 | $ | 290 | $ | 51 | |||||
Liabilities: | |||||||||||
Interest rate derivatives | $ | (219 | ) | $ | — | $ | (219 | ) | |||
Commodity derivatives: | |||||||||||
Natural Gas: | |||||||||||
Basis Swaps IFERC/NYMEX | (24 | ) | (24 | ) | — | ||||||
Swing Swaps IFERC | (15 | ) | (1 | ) | (14 | ) | |||||
Fixed Swaps/Futures | (57 | ) | (57 | ) | — | ||||||
Forward Physical Swaps | (2 | ) | — | (2 | ) | ||||||
Power – Forwards | (22 | ) | — | (22 | ) | ||||||
NGLs – Forwards/Swaps | (186 | ) | (186 | ) | — | ||||||
Refined Products – Futures | (25 | ) | (25 | ) | — | ||||||
Crude: | |||||||||||
Forwards/Swaps | (6 | ) | (6 | ) | — | ||||||
Futures | (1 | ) | (1 | ) | — | ||||||
Total commodity derivatives | (338 | ) | (300 | ) | (38 | ) | |||||
Total liabilities | $ | (557 | ) | $ | (300 | ) | $ | (257 | ) |
7. | NET INCOME (LOSS) PER LIMITED PARTNER UNIT |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017* | 2018 | 2017* | ||||||||||||
Net income | $ | 602 | $ | 296 | $ | 1,481 | $ | 689 | |||||||
Less: Income attributable to noncontrolling interest | 170 | 94 | 334 | 156 | |||||||||||
Net income, net of noncontrolling interest | 432 | 202 | 1,147 | 533 | |||||||||||
Series A Preferred Unitholders’ interest in net income | 15 | — | 30 | — | |||||||||||
Series B Preferred Unitholders’ interest in net income | 9 | — | 18 | — | |||||||||||
Series C Preferred Unitholders’ interest in net income | 6 | — | 6 | — | |||||||||||
General Partner’s interest in net income | 402 | 251 | 804 | 457 | |||||||||||
Class H Unitholder’s interest in net income | — | — | — | 93 | |||||||||||
Common Unitholders’ interest in net income (loss) | — | (49 | ) | 289 | (17 | ) | |||||||||
Additional (earnings) distributions allocated to General Partner | (1 | ) | 15 | (3 | ) | 12 | |||||||||
Distributions on employee unit awards, net of allocation to General Partner | (7 | ) | (6 | ) | (15 | ) | (13 | ) | |||||||
Net income (loss) available to Common Unitholders | $ | (8 | ) | $ | (40 | ) | $ | 271 | $ | (18 | ) | ||||
Weighted average Common Units – basic | 1,165.4 | 1,021.7 | 1,164.6 | 922.5 | |||||||||||
Basic net income (loss) per Common Unit | $ | (0.01 | ) | $ | (0.04 | ) | $ | 0.23 | $ | (0.02 | ) | ||||
Weighted average Common Units – diluted | 1,165.4 | 1,021.7 | 1,169.4 | 922.5 | |||||||||||
Diluted net income (loss) per Common Unit | $ | (0.01 | ) | $ | (0.04 | ) | $ | 0.23 | $ | (0.02 | ) |
8. | DEBT OBLIGATIONS |
9. | EQUITY |
Number of Units | |||
Number of common units at December 31, 2017 | 1,164.1 | ||
Common units issued in connection with the distribution reinvestment plan | 2.1 | ||
Common units issued in connection with certain transactions | 1.3 | ||
Issuance of common units under equity incentive plans | 0.1 | ||
Repurchases of common units in open-market transactions | (1.2 | ) | |
Number of common units at June 30, 2018 | 1,166.4 |
Quarter Ended | Record Date | Payment Date | Rate | |||||
December 31, 2017 | February 8, 2018 | February 14, 2018 | $ | 0.5650 | ||||
March 31, 2018 | May 7, 2018 | May 15, 2018 | 0.5650 | |||||
June 30, 2018 | August 6, 2018 | August 14, 2018 | 0.5650 |
Year Ending December 31, | ||||
2018 (remainder) | $ | 69 | ||
2019 | 128 | |||
Each year beyond 2019 | 33 |
Period Ended | Record Date | Payment Date | Rate | |||||
Series A Preferred Units | ||||||||
December 31, 2017 | February 1, 2018 | February 15, 2018 | $ | 15.451 | ||||
June 30, 2018 | August 1, 2018 | August 15, 2018 | 31.250 | |||||
Series B Preferred Units | ||||||||
December 31, 2017 | February 1, 2018 | February 15, 2018 | $ | 16.378 | ||||
June 30, 2018 | August 1, 2018 | August 15, 2018 | 33.125 | |||||
Series C Preferred Units | ||||||||
June 30, 2018 | August 1, 2018 | August 15, 2018 | $ | 0.56337 |
June 30, 2018 | December 31, 2017 | ||||||
Available-for-sale securities (1) | $ | 4 | $ | 8 | |||
Foreign currency translation adjustment | (5 | ) | (5 | ) | |||
Actuarial loss related to pensions and other postretirement benefits | (7 | ) | (5 | ) | |||
Investments in unconsolidated affiliates, net | 12 | 5 | |||||
Total AOCI, net of tax | $ | 4 | $ | 3 |
(1) | Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale securities to common unitholders. |
10. | INCOME TAXES |
11. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES |
• | $1.00 billion aggregate principal amount of 4.875% senior notes due 2023; |
• | $800 million aggregate principal amount of 5.50% senior notes due 2026; and |
• | $400 million aggregate principal amount of 5.875% senior notes due 2028. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Rental expense | $ | 22 | $ | 19 | $ | 39 | $ | 39 |
• | certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. |
• | certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. |
• | legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites. |
• | Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of June 30, 2018, Sunoco, Inc. had been named as a PRP at approximately 41 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. |
June 30, 2018 | December 31, 2017 | ||||||
Current | $ | 42 | $ | 36 | |||
Non-current | 276 | 314 | |||||
Total environmental liabilities | $ | 318 | $ | 350 |
12. | REVENUE |
• | intrastate transportation and storage; |
• | interstate transportation and storage; |
• | midstream; |
• | NGL and refined products transportation and services; |
• | crude oil transportation and services; and |
• | all other. |
• | In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed. |
• | Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received. |
2018 (remainder) | 2019 | 2020 | Thereafter | Total | ||||||||||||||||
Revenue expected to be recognized on contracts with customers existing as of June 30, 2018 | $ | 2,598 | $ | 5,048 | $ | 4,604 | $ | 28,071 | $ | 40,321 |
• | Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds |
• | Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less. |
• | Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components. |
13. | DERIVATIVE ASSETS AND LIABILITIES |
June 30, 2018 | December 31, 2017 | ||||||||
Notional Volume | Maturity | Notional Volume | Maturity | ||||||
Mark-to-Market Derivatives | |||||||||
(Trading) | |||||||||
Natural Gas (BBtu): | |||||||||
Fixed Swaps/Futures | 465 | 2018 | 1,078 | 2018 | |||||
Basis Swaps IFERC/NYMEX (1) | 102,328 | 2018-2020 | 48,510 | 2018-2020 | |||||
Options – Puts | (3,043 | ) | 2018 | 13,000 | 2018 | ||||
Power (Megawatt): | |||||||||
Forwards | 3,196,100 | 2018-2019 | 435,960 | 2018-2019 | |||||
Futures | (42,768 | ) | 2018 | (25,760 | ) | 2018 | |||
Options – Puts | (30,532 | ) | 2018 | (153,600 | ) | 2018 | |||
Options – Calls | 996,172 | 2018 | 137,600 | 2018 | |||||
(Non-Trading) | |||||||||
Natural Gas (BBtu): | |||||||||
Basis Swaps IFERC/NYMEX | 6,600 | 2018-2020 | 4,650 | 2018-2020 | |||||
Swing Swaps IFERC | 52,413 | 2018-2019 | 87,253 | 2018-2019 | |||||
Fixed Swaps/Futures | 5,360 | 2018-2019 | (4,700 | ) | 2018-2019 | ||||
Forward Physical Contracts | (174,465 | ) | 2018-2020 | (145,105 | ) | 2018-2020 | |||
NGL (MBbls) – Forwards/Swaps | (1,590 | ) | 2018-2019 | (2,493 | ) | 2018-2019 | |||
Crude (MBbls) – Forwards/Swaps | 44,190 | 2018-2019 | 9,172 | 2018-2019 | |||||
Refined Products (MBbls) – Futures | (1,076 | ) | 2018-2019 | (3,783 | ) | 2018-2019 | |||
Fair Value Hedging Derivatives | |||||||||
(Non-Trading) | |||||||||
Natural Gas (BBtu): | |||||||||
Basis Swaps IFERC/NYMEX | (21,475 | ) | 2018 | (39,770 | ) | 2018 | |||
Fixed Swaps/Futures | (21,475 | ) | 2018 | (39,770 | ) | 2018 | |||
Hedged Item – Inventory | 21,475 | 2018 | 39,770 | 2018 |
(1) | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Term | Type(1) | Notional Amount Outstanding | ||||||||
June 30, 2018 | December 31, 2017 | |||||||||
July 2018(2) | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | $ | — | $ | 300 | |||||
July 2019(2) | Forward-starting to pay a fixed rate of 3.56% and receive a floating rate | 400 | 300 | |||||||
July 2020(2) | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | 400 | 400 | |||||||
July 2021(2) | Forward-starting to pay a fixed rate of 3.55% and receive a floating rate | 400 | — | |||||||
December 2018 | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | 1,200 | 1,200 | |||||||
March 2019 | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | 300 | 300 |
(1) | Floating rates are based on 3-month LIBOR. |
(2) | Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. |
Fair Value of Derivative Instruments | ||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||
June 30, 2018 | December 31, 2017 | June 30, 2018 | December 31, 2017 | |||||||||||||
Derivatives designated as hedging instruments: | ||||||||||||||||
Commodity derivatives (margin deposits) | $ | — | $ | 14 | $ | (2 | ) | $ | (2 | ) | ||||||
Derivatives not designated as hedging instruments: | ||||||||||||||||
Commodity derivatives (margin deposits) | 307 | 262 | (352 | ) | (281 | ) | ||||||||||
Commodity derivatives | 106 | 44 | (422 | ) | (55 | ) | ||||||||||
Interest rate derivatives | — | — | (147 | ) | (219 | ) | ||||||||||
413 | 306 | (921 | ) | (555 | ) | |||||||||||
Total derivatives | $ | 413 | $ | 320 | $ | (923 | ) | $ | (557 | ) |
Asset Derivatives | Liability Derivatives | |||||||||||||||||
Balance Sheet Location | June 30, 2018 | December 31, 2017 | June 30, 2018 | December 31, 2017 | ||||||||||||||
Derivatives without offsetting agreements | Derivative liabilities | $ | — | $ | — | $ | (147 | ) | $ | (219 | ) | |||||||
Derivatives in offsetting agreements: | ||||||||||||||||||
OTC contracts | Derivative assets (liabilities) | 106 | 44 | (422 | ) | (55 | ) | |||||||||||
Broker cleared derivative contracts | Other current assets (liabilities) | 307 | 276 | (354 | ) | (283 | ) | |||||||||||
Total gross derivatives | 413 | 320 | (923 | ) | (557 | ) | ||||||||||||
Offsetting agreements: | ||||||||||||||||||
Counterparty netting | Derivative assets (liabilities) | (49 | ) | (20 | ) | 49 | 20 | |||||||||||
Counterparty netting | Other current assets (liabilities) | (306 | ) | (263 | ) | 306 | 263 | |||||||||||
Total net derivatives | $ | 58 | $ | 37 | $ | (568 | ) | $ | (274 | ) |
Location of Gain/(Loss) Recognized in Income on Derivatives | Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||||
Derivatives in fair value hedging relationships (including hedged item): | |||||||||||||||||
Commodity derivatives | Cost of products sold | $ | 6 | $ | 6 | $ | 9 | $ | 2 |
Location of Gain/(Loss) Recognized in Income on Derivatives | Amount of Gain/(Loss) Recognized in Income on Derivatives | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||
Commodity derivatives – Trading | Cost of products sold | $ | 16 | $ | 15 | $ | 33 | $ | 26 | ||||||||
Commodity derivatives – Non-trading | Cost of products sold | (300 | ) | 7 | (373 | ) | (3 | ) | |||||||||
Interest rate derivatives | Gains (losses) on interest rate derivatives | 20 | (25 | ) | 72 | (20 | ) | ||||||||||
Embedded derivatives | Other, net | — | — | — | 1 | ||||||||||||
Total | $ | (264 | ) | $ | (3 | ) | $ | (268 | ) | $ | 4 |
14. | RELATED PARTY TRANSACTIONS |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Affiliated revenues | $ | 222 | $ | 133 | $ | 508 | $ | 251 |
June 30, 2018 | December 31, 2017 | ||||||
Accounts receivable from related companies: | |||||||
Sunoco LP | $ | 184 | $ | 219 | |||
FGT | 18 | 11 | |||||
Other | 132 | 88 | |||||
Total accounts receivable from related companies: | $ | 334 | $ | 318 | |||
Accounts payable to related companies: | |||||||
Sunoco LP | $ | 195 | $ | 195 | |||
USAC | 45 | — | |||||
Other | 89 | 14 | |||||
Total accounts payable to related companies: | $ | 329 | $ | 209 |
June 30, 2018 | December 31, 2017 | ||||||
Long-term notes receivable from related company: | |||||||
Sunoco LP | $ | 85 | $ | 85 |
15. | REPORTABLE SEGMENTS |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Revenues: | |||||||||||||||
Intrastate transportation and storage: | |||||||||||||||
Revenues from external customers | $ | 761 | $ | 699 | $ | 1,578 | $ | 1,467 | |||||||
Intersegment revenues | 52 | 54 | 110 | 102 | |||||||||||
813 | 753 | 1,688 | 1,569 | ||||||||||||
Interstate transportation and storage: | |||||||||||||||
Revenues from external customers | 323 | 201 | 636 | 432 | |||||||||||
Intersegment revenues | 5 | 6 | 8 | 10 | |||||||||||
328 | 207 | 644 | 442 | ||||||||||||
Midstream: | |||||||||||||||
Revenues from external customers | 594 | 633 | 1,034 | 1,198 | |||||||||||
Intersegment revenues | 1,280 | 982 | 2,454 | 2,054 | |||||||||||
1,874 | 1,615 | 3,488 | 3,252 | ||||||||||||
NGL and refined products transportation and services: | |||||||||||||||
Revenues from external customers | 2,472 | 1,767 | 4,930 | 3,885 | |||||||||||
Intersegment revenues | 96 | 12 | 184 | 160 | |||||||||||
2,568 | 1,779 | 5,114 | 4,045 | ||||||||||||
Crude oil transportation and services: | |||||||||||||||
Revenues from external customers | 4,789 | 2,460 | 8,520 | 5,035 | |||||||||||
Intersegment revenues | 14 | 5 | 28 | 5 | |||||||||||
4,803 | 2,465 | 8,548 | 5,040 | ||||||||||||
All other: | |||||||||||||||
Revenues from external customers | 471 | 816 | 992 | 1,454 | |||||||||||
Intersegment revenues | 31 | 54 | 81 | 186 | |||||||||||
502 | 870 | 1,073 | 1,640 | ||||||||||||
Eliminations | (1,478 | ) | (1,113 | ) | (2,865 | ) | (2,517 | ) | |||||||
Total revenues | $ | 9,410 | $ | 6,576 | $ | 17,690 | $ | 13,471 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017* | 2018 | 2017* | ||||||||||||
Segment Adjusted EBITDA: | |||||||||||||||
Intrastate transportation and storage | $ | 208 | $ | 148 | $ | 400 | $ | 317 | |||||||
Interstate transportation and storage | 330 | 262 | 653 | 527 | |||||||||||
Midstream | 414 | 412 | 791 | 732 | |||||||||||
NGL and refined products transportation and services | 461 | 388 | 912 | 769 | |||||||||||
Crude oil transportation and services | 548 | 228 | 1,012 | 415 | |||||||||||
All other | 90 | 107 | 164 | 230 | |||||||||||
Total | 2,051 | 1,545 | 3,932 | 2,990 | |||||||||||
Depreciation, depletion and amortization | (588 | ) | (557 | ) | (1,191 | ) | (1,117 | ) | |||||||
Interest expense, net | (358 | ) | (336 | ) | (704 | ) | (668 | ) | |||||||
Gain on Sunoco LP common unit repurchase | — | — | 172 | — | |||||||||||
Loss on deconsolidation of CDM | (86 | ) | — | (86 | ) | — | |||||||||
Gains (losses) on interest rate derivatives | 20 | (25 | ) | 72 | (20 | ) | |||||||||
Non-cash compensation expense | (21 | ) | (15 | ) | (41 | ) | (38 | ) | |||||||
Unrealized gains (losses) on commodity risk management activities | (265 | ) | 34 | (352 | ) | 98 | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | (228 | ) | (247 | ) | (413 | ) | (486 | ) | |||||||
Equity in earnings (losses) of unconsolidated affiliates | 106 | (61 | ) | 34 | 12 | ||||||||||
Other, net | 40 | 37 | 87 | 52 | |||||||||||
Income before income tax expense | $ | 671 | $ | 375 | $ | 1,510 | $ | 823 |
June 30, 2018 | December 31, 2017 | ||||||
Assets: | |||||||
Intrastate transportation and storage | $ | 5,604 | $ | 5,020 | |||
Interstate transportation and storage | 14,037 | 13,518 | |||||
Midstream | 19,949 | 20,004 | |||||
NGL and refined products transportation and services | 17,517 | 17,600 | |||||
Crude oil transportation and services | 18,168 | 17,736 | |||||
All other | 3,295 | 4,087 | |||||
Total assets | $ | 78,570 | $ | 77,965 |
16. | CONSOLIDATING GUARANTOR FINANCIAL INFORMATION |
June 30, 2018 | |||||||||||||||||||
Parent Guarantor | Subsidiary Issuer | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Cash and cash equivalents | $ | — | $ | — | $ | 494 | $ | — | $ | 494 | |||||||||
All other current assets | — | 57 | 8,527 | (2,531 | ) | 6,053 | |||||||||||||
Property, plant and equipment, net | — | — | 59,776 | — | 59,776 | ||||||||||||||
Investments in unconsolidated affiliates | 51,199 | 12,078 | 3,636 | (63,277 | ) | 3,636 | |||||||||||||
All other assets | 8 | — | 8,603 | — | 8,611 | ||||||||||||||
Total assets | $ | 51,207 | $ | 12,135 | $ | 81,036 | $ | (65,808 | ) | $ | 78,570 | ||||||||
Current liabilities | $ | 390 | $ | (3,571 | ) | $ | 12,353 | $ | (2,531 | ) | $ | 6,641 | |||||||
Non-current liabilities | 22,949 | 7,606 | 7,338 | — | 37,893 | ||||||||||||||
Noncontrolling interest | — | — | 6,171 | — | 6,171 | ||||||||||||||
Total partners’ capital | 27,868 | 8,100 | 55,174 | (63,277 | ) | 27,865 | |||||||||||||
Total liabilities and equity | $ | 51,207 | $ | 12,135 | $ | 81,036 | $ | (65,808 | ) | $ | 78,570 |
December 31, 2017 | |||||||||||||||||||
Parent Guarantor | Subsidiary Issuer | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Cash and cash equivalents | $ | — | $ | (3 | ) | $ | 309 | $ | — | $ | 306 | ||||||||
All other current assets | — | 159 | 6,063 | — | 6,222 | ||||||||||||||
Property, plant and equipment, net | — | — | 58,437 | — | 58,437 | ||||||||||||||
Investments in unconsolidated affiliates | 48,378 | 11,648 | 3,816 | (60,026 | ) | 3,816 | |||||||||||||
All other assets | — | — | 9,184 | — | 9,184 | ||||||||||||||
Total assets | $ | 48,378 | $ | 11,804 | $ | 77,809 | $ | (60,026 | ) | $ | 77,965 | ||||||||
Current liabilities | $ | (1,496 | ) | $ | (3,660 | ) | $ | 12,150 | $ | — | $ | 6,994 | |||||||
Non-current liabilities | 21,604 | 7,607 | 7,609 | — | 36,820 | ||||||||||||||
Noncontrolling interest | — | — | 5,882 | — | 5,882 | ||||||||||||||
Total partners’ capital | 28,270 | 7,857 | 52,168 | (60,026 | ) | 28,269 | |||||||||||||
Total liabilities and equity | $ | 48,378 | $ | 11,804 | $ | 77,809 | $ | (60,026 | ) | $ | 77,965 |
Three Months Ended June 30, 2018 | |||||||||||||||||||
Parent Guarantor | Subsidiary Issuer | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Revenues | $ | — | $ | — | $ | 9,410 | $ | — | $ | 9,410 | |||||||||
Operating costs, expenses, and other | — | — | 8,467 | — | 8,467 | ||||||||||||||
Operating income | — | — | 943 | — | 943 | ||||||||||||||
Interest expense, net | (289 | ) | (41 | ) | (28 | ) | — | (358 | ) | ||||||||||
Equity in earnings of unconsolidated affiliates | 701 | 66 | 106 | (767 | ) | 106 | |||||||||||||
Gains on interest rate derivatives | 20 | — | — | — | 20 | ||||||||||||||
Loss on deconsolidation of CDM | — | — | (86 | ) | — | (86 | ) | ||||||||||||
Other, net | — | — | 46 | — | 46 | ||||||||||||||
Income before income tax expense | 432 | 25 | 981 | (767 | ) | 671 | |||||||||||||
Income tax expense | — | — | 69 | — | 69 | ||||||||||||||
Net income | 432 | 25 | 912 | (767 | ) | 602 | |||||||||||||
Less: Net income attributable to noncontrolling interest | — | — | 170 | — | 170 | ||||||||||||||
Net income attributable to partners | $ | 432 | $ | 25 | $ | 742 | $ | (767 | ) | $ | 432 | ||||||||
Other comprehensive income | $ | — | $ | — | $ | 2 | $ | — | $ | 2 | |||||||||
Comprehensive income | 432 | 25 | 914 | (767 | ) | 604 | |||||||||||||
Comprehensive income attributable to noncontrolling interest | — | — | 170 | — | 170 | ||||||||||||||
Comprehensive income attributable to partners | $ | 432 | $ | 25 | $ | 744 | $ | (767 | ) | $ | 434 |
Three Months Ended June 30, 2017* | |||||||||||||||||||
Parent Guarantor | Subsidiary Issuer | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Revenues | $ | — | $ | — | $ | 6,576 | $ | — | $ | 6,576 | |||||||||
Operating costs, expenses, and other | — | 1 | 5,839 | — | 5,840 | ||||||||||||||
Operating income (loss) | — | (1 | ) | 737 | — | 736 | |||||||||||||
Interest expense, net | — | (39 | ) | (297 | ) | — | (336 | ) | |||||||||||
Equity in earnings (losses) of unconsolidated affiliates | 199 | 137 | (61 | ) | (336 | ) | (61 | ) | |||||||||||
Losses on interest rate derivatives | — | — | (25 | ) | — | (25 | ) | ||||||||||||
Other, net | — | 3 | 59 | (1 | ) | 61 | |||||||||||||
Income before income tax expense | 199 | 100 | 413 | (337 | ) | 375 | |||||||||||||
Income tax expense | — | — | 79 | — | 79 | ||||||||||||||
Net income | 199 | 100 | 334 | (337 | ) | 296 | |||||||||||||
Less: Net income attributable to noncontrolling interest | — | — | 94 | — | 94 | ||||||||||||||
Net income attributable to partners | $ | 199 | $ | 100 | $ | 240 | $ | (337 | ) | $ | 202 | ||||||||
Other comprehensive loss | $ | — | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | |||||||
Comprehensive income | 199 | 100 | 333 | (337 | ) | 295 | |||||||||||||
Comprehensive income attributable to noncontrolling interest | — | — | 94 | — | 94 | ||||||||||||||
Comprehensive income attributable to partners | $ | 199 | $ | 100 | $ | 239 | $ | (337 | ) | $ | 201 |
Six Months Ended June 30, 2018 | |||||||||||||||||||
Parent Guarantor | Subsidiary Issuer | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Revenues | $ | — | $ | — | $ | 17,690 | $ | — | $ | 17,690 | |||||||||
Operating costs, expenses, and other | — | — | 15,774 | — | 15,774 | ||||||||||||||
Operating income | — | — | 1,916 | — | 1,916 | ||||||||||||||
Interest expense, net | (567 | ) | (82 | ) | (55 | ) | — | (704 | ) | ||||||||||
Equity in earnings of unconsolidated affiliates | 1,642 | 326 | 34 | (1,968 | ) | 34 | |||||||||||||
Gains on interest rate derivatives | 72 | — | — | — | 72 | ||||||||||||||
Gain on Sunoco LP unit repurchase | — | — | 172 | — | 172 | ||||||||||||||
Loss on deconsolidation of CDM | — | — | (86 | ) | — | (86 | ) | ||||||||||||
Other, net | — | — | 106 | — | 106 | ||||||||||||||
Income before income tax expense | 1,147 | 244 | 2,087 | (1,968 | ) | 1,510 | |||||||||||||
Income tax expense | — | — | 29 | — | 29 | ||||||||||||||
Net income | 1,147 | 244 | 2,058 | (1,968 | ) | 1,481 | |||||||||||||
Less: Net income attributable to noncontrolling interest | — | — | 334 | — | 334 | ||||||||||||||
Net income attributable to partners | $ | 1,147 | $ | 244 | $ | 1,724 | $ | (1,968 | ) | $ | 1,147 | ||||||||
Other comprehensive income | $ | — | $ | — | $ | 3 | $ | — | $ | 3 | |||||||||
Comprehensive income | 1,147 | 244 | 2,061 | (1,968 | ) | 1,484 | |||||||||||||
Comprehensive income attributable to noncontrolling interest | — | — | 334 | — | 334 | ||||||||||||||
Comprehensive income attributable to partners | $ | 1,147 | $ | 244 | $ | 1,727 | $ | (1,968 | ) | $ | 1,150 |
Six Months Ended June 30, 2017* | |||||||||||||||||||
Parent Guarantor | Subsidiary Issuer | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Revenues | $ | — | $ | — | $ | 13,471 | $ | — | $ | 13,471 | |||||||||
Operating costs, expenses, and other | — | 1 | 12,051 | — | 12,052 | ||||||||||||||
Operating income (loss) | — | (1 | ) | 1,420 | — | 1,419 | |||||||||||||
Interest expense, net | — | (81 | ) | (587 | ) | — | (668 | ) | |||||||||||
Equity in earnings of unconsolidated affiliates | 1,010 | 765 | 12 | (1,775 | ) | 12 | |||||||||||||
Losses on interest rate derivatives | — | — | (20 | ) | — | (20 | ) | ||||||||||||
Other, net | — | 3 | 78 | (1 | ) | 80 | |||||||||||||
Income before income tax expense | 1,010 | 686 | 903 | (1,776 | ) | 823 | |||||||||||||
Income tax expense | — | — | 134 | — | 134 | ||||||||||||||
Net income | 1,010 | 686 | 769 | (1,776 | ) | 689 | |||||||||||||
Less: Net income attributable to noncontrolling interest | — | — | 156 | — | 156 | ||||||||||||||
Net income attributable to partners | $ | 1,010 | $ | 686 | $ | 613 | $ | (1,776 | ) | $ | 533 | ||||||||
Other comprehensive loss | $ | — | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | |||||||
Comprehensive income | 1,010 | 686 | 768 | (1,776 | ) | 688 | |||||||||||||
Comprehensive income attributable to noncontrolling interest | — | — | 156 | — | 156 | ||||||||||||||
Comprehensive income attributable to partners | $ | 1,010 | $ | 686 | $ | 612 | $ | (1,776 | ) | $ | 532 |
Six Months Ended June 30, 2018 | |||||||||||||||||||
Parent Guarantor | Subsidiary Issuer | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Cash flows provided by operating activities | $ | 3,252 | $ | 102 | $ | 585 | $ | (989 | ) | $ | 2,950 | ||||||||
Cash flows used in investing activities | (2,925 | ) | (99 | ) | (903 | ) | 2,336 | (1,591 | ) | ||||||||||
Cash flows provided by (used in) financing activities | (327 | ) | — | 503 | (1,347 | ) | (1,171 | ) | |||||||||||
Change in cash | — | 3 | 185 | — | 188 | ||||||||||||||
Cash at beginning of period | — | (3 | ) | 309 | — | 306 | |||||||||||||
Cash at end of period | $ | — | $ | — | $ | 494 | $ | — | $ | 494 |
Six Months Ended June 30, 2017 | |||||||||||||||||||
Parent Guarantor | Subsidiary Issuer | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Cash flows provided by operating activities | $ | 1,010 | $ | 652 | $ | 1,764 | $ | (1,776 | ) | $ | 1,650 | ||||||||
Cash flows used in investing activities | (716 | ) | (421 | ) | (2,125 | ) | 1,776 | (1,486 | ) | ||||||||||
Cash flows provided by (used in) financing activities | (294 | ) | (249 | ) | 291 | — | (252 | ) | |||||||||||
Change in cash | — | (18 | ) | (70 | ) | — | (88 | ) | |||||||||||
Cash at beginning of period | — | 41 | 319 | — | 360 | ||||||||||||||
Cash at end of period | $ | — | $ | 23 | $ | 249 | $ | — | $ | 272 |
• | Natural gas operations, including the following: |
• | natural gas midstream and intrastate transportation and storage; and |
• | interstate natural gas transportation and storage. |
• | Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017* | Change | 2018 | 2017* | Change | ||||||||||||||||||
Segment Adjusted EBITDA: | |||||||||||||||||||||||
Intrastate transportation and storage | $ | 208 | $ | 148 | $ | 60 | $ | 400 | $ | 317 | $ | 83 | |||||||||||
Interstate transportation and storage | 330 | 262 | 68 | 653 | 527 | 126 | |||||||||||||||||
Midstream | 414 | 412 | 2 | 791 | 732 | 59 | |||||||||||||||||
NGL and refined products transportation and services | 461 | 388 | 73 | 912 | 769 | 143 | |||||||||||||||||
Crude oil transportation and services | 548 | 228 | 320 | 1,012 | 415 | 597 | |||||||||||||||||
All other | 90 | 107 | (17 | ) | 164 | 230 | (66 | ) | |||||||||||||||
Total | 2,051 | 1,545 | 506 | 3,932 | 2,990 | 942 | |||||||||||||||||
Depreciation, depletion and amortization | (588 | ) | (557 | ) | (31 | ) | (1,191 | ) | (1,117 | ) | (74 | ) | |||||||||||
Interest expense, net | (358 | ) | (336 | ) | (22 | ) | (704 | ) | (668 | ) | (36 | ) | |||||||||||
Gain on Sunoco LP common unit repurchase | — | — | — | 172 | — | 172 | |||||||||||||||||
Loss on deconsolidation of CDM | (86 | ) | — | (86 | ) | (86 | ) | — | (86 | ) | |||||||||||||
Gains (losses) on interest rate derivatives | 20 | (25 | ) | 45 | 72 | (20 | ) | 92 | |||||||||||||||
Non-cash compensation expense | (21 | ) | (15 | ) | (6 | ) | (41 | ) | (38 | ) | (3 | ) | |||||||||||
Unrealized gains (losses) on commodity risk management activities | (265 | ) | 34 | (299 | ) | (352 | ) | 98 | (450 | ) | |||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | (228 | ) | (247 | ) | 19 | (413 | ) | (486 | ) | 73 | |||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | 106 | (61 | ) | 167 | 34 | 12 | 22 | ||||||||||||||||
Other, net | 40 | 37 | 3 | 87 | 52 | 35 | |||||||||||||||||
Income before income tax expense | 671 | 375 | 296 | 1,510 | 823 | 687 | |||||||||||||||||
Income tax expense | (69 | ) | (79 | ) | 10 | (29 | ) | (134 | ) | 105 | |||||||||||||
Net income | $ | 602 | $ | 296 | $ | 306 | $ | 1,481 | $ | 689 | $ | 792 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
Equity in earnings (losses) of unconsolidated affiliates: | |||||||||||||||||||||||
Citrus | $ | 33 | $ | 30 | $ | 3 | $ | 60 | $ | 51 | $ | 9 | |||||||||||
FEP | 13 | 13 | — | 27 | 25 | 2 | |||||||||||||||||
MEP | 8 | 10 | (2 | ) | 17 | 20 | (3 | ) | |||||||||||||||
Sunoco LP | 16 | (110 | ) | 126 | (135 | ) | (124 | ) | (11 | ) | |||||||||||||
USAC | (2 | ) | — | (2 | ) | (2 | ) | — | (2 | ) | |||||||||||||
Other | 38 | (4 | ) | 42 | 67 | 40 | 27 | ||||||||||||||||
Total equity in earnings (losses) of unconsolidated affiliates | $ | 106 | $ | (61 | ) | $ | 167 | $ | 34 | $ | 12 | $ | 22 | ||||||||||
Adjusted EBITDA related to unconsolidated affiliates(1): | |||||||||||||||||||||||
Citrus | $ | 85 | $ | 88 | $ | (3 | ) | $ | 160 | $ | 163 | $ | (3 | ) | |||||||||
FEP | 18 | 19 | (1 | ) | 37 | 37 | — | ||||||||||||||||
MEP | 20 | 21 | (1 | ) | 42 | 43 | (1 | ) | |||||||||||||||
Sunoco LP | 39 | 83 | (44 | ) | 68 | 137 | (69 | ) | |||||||||||||||
USAC | 21 | — | 21 | 21 | — | 21 | |||||||||||||||||
Other | 45 | 36 | 9 | 85 | 106 | (21 | ) | ||||||||||||||||
Total Adjusted EBITDA related to unconsolidated affiliates | $ | 228 | $ | 247 | $ | (19 | ) | $ | 413 | $ | 486 | $ | (73 | ) | |||||||||
Distributions received from unconsolidated affiliates: | |||||||||||||||||||||||
Citrus | $ | 27 | $ | 22 | $ | 5 | $ | 73 | $ | 63 | $ | 10 | |||||||||||
FEP | 15 | 10 | 5 | 32 | 10 | 22 | |||||||||||||||||
MEP | 18 | 20 | (2 | ) | 31 | 93 | (62 | ) | |||||||||||||||
Sunoco LP | 22 | 37 | (15 | ) | 58 | 72 | (14 | ) | |||||||||||||||
USAC | 10 | — | 10 | 10 | — | 10 | |||||||||||||||||
Other | 21 | 30 | (9 | ) | 42 | 53 | (11 | ) | |||||||||||||||
Total distributions received from unconsolidated affiliates | $ | 113 | $ | 119 | $ | (6 | ) | $ | 246 | $ | 291 | $ | (45 | ) |
(1) | These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes. |
• | Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment. |
• | Unrealized gains or losses on commodity risk management activities. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure. |
• | Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure. |
• | Adjusted EBITDA related to unconsolidated affiliates. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Intrastate transportation and storage | $ | 267 | $ | 202 | $ | 438 | $ | 384 | |||||||
Interstate transportation and storage | 328 | 207 | 644 | $ | 442 | ||||||||||
Midstream | 593 | 571 | 1,146 | 1,084 | |||||||||||
NGL and refined products transportation and services | 587 | 516 | 1,187 | 1,075 | |||||||||||
Crude oil transportation and services | 442 | 374 | 1,010 | 646 | |||||||||||
All other | 57 | 76 | 152 | 178 | |||||||||||
Intersegment eliminations | (4 | ) | 6 | (15 | ) | (12 | ) | ||||||||
Total segment margin | 2,270 | 1,952 | 4,562 | 3,797 | |||||||||||
Less: | |||||||||||||||
Operating expenses | 627 | 539 | 1,231 | 1,031 | |||||||||||
Depreciation, depletion and amortization | 588 | 557 | 1,191 | 1,117 | |||||||||||
Selling, general and administrative | 112 | 120 | 224 | 230 | |||||||||||
Operating income | $ | 943 | $ | 736 | $ | 1,916 | $ | 1,419 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
Natural gas transported (BBtu/d) | 10,327 | 9,261 | 1,066 | 9,802 | 8,569 | 1,233 | |||||||||||||||||
Withdrawals from storage natural gas inventory (BBtu) | — | — | — | 17,703 | 23,093 | (5,390 | ) | ||||||||||||||||
Revenues | $ | 813 | $ | 753 | $ | 60 | $ | 1,688 | $ | 1,569 | $ | 119 | |||||||||||
Cost of products sold | 546 | 551 | (5 | ) | 1,250 | 1,185 | 65 | ||||||||||||||||
Segment margin | 267 | 202 | 65 | 438 | 384 | 54 | |||||||||||||||||
Unrealized (gains) losses on commodity risk management activities | (8 | ) | (21 | ) | 13 | 45 | (6 | ) | 51 | ||||||||||||||
Operating expenses, excluding non-cash compensation expense | (51 | ) | (46 | ) | (5 | ) | (90 | ) | (84 | ) | (6 | ) | |||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (7 | ) | (5 | ) | (2 | ) | (13 | ) | (11 | ) | (2 | ) | |||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 7 | 18 | (11 | ) | 20 | 34 | (14 | ) | |||||||||||||||
Segment Adjusted EBITDA | $ | 208 | $ | 148 | $ | 60 | $ | 400 | $ | 317 | $ | 83 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
Transportation fees | $ | 134 | $ | 104 | $ | 30 | $ | 251 | $ | 228 | $ | 23 | |||||||||||
Natural gas sales and other (excluding unrealized gains and losses) | 108 | 61 | 47 | 199 | 94 | 105 | |||||||||||||||||
Retained fuel revenues (excluding unrealized gains and losses) | 13 | 15 | (2 | ) | 26 | 28 | (2 | ) | |||||||||||||||
Storage margin (excluding unrealized gains and losses) | 4 | 1 | 3 | 7 | 28 | (21 | ) | ||||||||||||||||
Unrealized gains (losses) on commodity risk management activities | 8 | 21 | (13 | ) | (45 | ) | 6 | (51 | ) | ||||||||||||||
Total segment margin | $ | 267 | $ | 202 | $ | 65 | $ | 438 | $ | 384 | $ | 54 |
• | an increase of $47 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity; |
• | a net increase of $5 million due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $26 million, $6 million and $2 million, respectively, and a decrease of $13 million in Adjusted EBITDA related to unconsolidated affiliates; |
• | an increase of $4 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to higher demand on existing pipelines; and |
• | an increase of $3 million in realized storage margin primarily due to higher realized derivative gains; partially offset by |
• | a decrease of $2 million in retained fuel revenues as a result of lower natural gas pricing. |
• | an increase of $105 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; and |
• | a net increase of $5 million due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $26 million, $6 million and $2 million, respectively, and a decrease of $15 million in Adjusted EBITDA related to unconsolidated affiliates; partially offset by |
• | a decrease of $21 million in realized storage margin primarily due to an adjustment to the Bammel storage inventory; |
• | a decrease of $3 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to renegotiated contracts; and |
• | a decrease of $2 million in retained fuel revenues due to lower natural gas pricing. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
Natural gas transported (BBtu/d) | 8,707 | 5,299 | 3,408 | 8,457 | 5,476 | 2,981 | |||||||||||||||||
Natural gas sold (BBtu/d) | 17 | 17 | — | 17 | 17 | — | |||||||||||||||||
Revenues | $ | 328 | $ | 207 | $ | 121 | $ | 644 | $ | 442 | $ | 202 | |||||||||||
Operating expenses, excluding non-cash compensation, amortization and accretion expenses | (105 | ) | (67 | ) | (38 | ) | (199 | ) | (141 | ) | (58 | ) | |||||||||||
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses | (17 | ) | (7 | ) | (10 | ) | (34 | ) | (19 | ) | (15 | ) | |||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 123 | 128 | (5 | ) | 239 | 243 | (4 | ) | |||||||||||||||
Other | 1 | 1 | — | 3 | 2 | 1 | |||||||||||||||||
Segment Adjusted EBITDA | $ | 330 | $ | 262 | $ | 68 | $ | 653 | $ | 527 | $ | 126 |
• | an increase of $68 million from the partial in service of the Rover pipeline with increases of $105 million in revenues, $30 million in operating expenses and $7 million in selling, general and administrative expenses; and |
• | an aggregate increase of $19 million in revenues, excluding the incremental revenue related to the Rover pipeline in service discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by $3 million of lower revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by |
• | an increase of $8 million in operating expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to higher maintenance project costs; |
• | an increase of $3 million in selling, general and administrative expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to a reimbursement of legal fees and a franchise tax settlement received in 2017; and |
• | a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short-term firm capacity on Citrus. |
• | An increase of $117 million from the partial in service of the Rover pipeline with increases of $187 million in revenues, $56 million in operating expenses and $14 million in selling, general and administrative expenses; and |
• | an aggregate increase of $21 million in revenues, excluding the incremental revenues related to the Rover pipeline in service discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by $6 million of lower revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by |
• | an increase of $2 million in operating expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to higher maintenance project costs; and |
• | a decrease of $4 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short term firm capacity on Citrus. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
Gathered volumes (BBtu/d) | 11,576 | 10,961 | 615 | 11,442 | 10,599 | 843 | |||||||||||||||||
NGLs produced (MBbls/d) | 513 | 474 | 39 | 508 | 459 | 49 | |||||||||||||||||
Equity NGLs (MBbls/d) | 31 | 28 | 3 | 30 | 27 | 3 | |||||||||||||||||
Revenues | $ | 1,874 | $ | 1,615 | $ | 259 | $ | 3,488 | $ | 3,252 | $ | 236 | |||||||||||
Cost of products sold | 1,281 | 1,044 | 237 | 2,342 | 2,168 | 174 | |||||||||||||||||
Segment margin | 593 | 571 | 22 | 1,146 | 1,084 | 62 | |||||||||||||||||
Unrealized gains on commodity risk management activities | — | (3 | ) | 3 | — | (19 | ) | 19 | |||||||||||||||
Operating expenses, excluding non-cash compensation expense | (169 | ) | (152 | ) | (17 | ) | (333 | ) | (313 | ) | (20 | ) | |||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (20 | ) | (11 | ) | (9 | ) | (40 | ) | (34 | ) | (6 | ) | |||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 9 | 7 | 2 | 16 | 14 | 2 | |||||||||||||||||
Other | 1 | — | 1 | 2 | — | 2 | |||||||||||||||||
Segment Adjusted EBITDA | $ | 414 | $ | 412 | $ | 2 | $ | 791 | $ | 732 | $ | 59 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
Gathering and processing fee-based revenues | $ | 453 | $ | 436 | $ | 17 | $ | 874 | $ | 844 | $ | 30 | |||||||||||
Non-fee-based contracts and processing (excluding unrealized gains and losses) | 140 | 132 | 8 | 272 | 221 | 51 | |||||||||||||||||
Unrealized gains on commodity risk management activities | — | 3 | (3 | ) | — | 19 | (19 | ) | |||||||||||||||
Total segment margin | $ | 593 | $ | 571 | $ | 22 | $ | 1,146 | $ | 1,084 | $ | 62 |
• | an increase of $17 million in fee-based margin due to growth in the Permian and Northeast regions, offset by declines in the South Texas, North Texas and midcontinent/Panhandle regions; |
• | an increase of $6 million in non-fee-based margin primarily due to higher crude oil and NGL prices; |
• | an increase of $2 million in non-fee-based margin due to increased throughput volume in the Permian region; and |
• | an increase of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by |
• | an increase of $17 million in operating expenses primarily due to increases of $6 million in outside services, $5 million in materials, $2 million in employee costs and $2 million in ad valorem taxes; and |
• | an increase of $9 million in selling, general and administrative expenses primarily due to a favorable impact recorded in the prior period from the adjustment of certain reserves in connection with contingent matters. |
• | an increase of $27 million in non-fee-based margin primarily due to higher crude oil and NGL prices; |
• | an increase of $24 million in non-fee-based margin due to increased throughput volume in the Permian region; |
• | an increase of $30 million in fee-based margin due to growth in the Permian and Northeast regions, offset by declines in the South Texas, North Texas and midcontinent/Panhandle regions; and |
• | an increase of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by |
• | an increase of $20 million in operating expenses due to increases of $8 million in outside services, $5 million in materials, $4 million in employee costs and $3 million in ad valorem taxes; and |
• | an increase of $6 million in selling, general and administrative expenses primarily due to a favorable impact recorded in the prior period from the adjustment of certain reserves in connection with contingent matters. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
NGL transportation volumes (MBbls/d) | 967 | 835 | 132 | 951 | 823 | 128 | |||||||||||||||||
Refined products transportation volumes (MBbls/d) | 637 | 643 | (6 | ) | 629 | 633 | (4 | ) | |||||||||||||||
NGL and refined products terminal volumes (MBbls/d) | 789 | 767 | 22 | 746 | 779 | (33 | ) | ||||||||||||||||
NGL fractionation volumes (MBbls/d) | 473 | 431 | 42 | 473 | 430 | 43 | |||||||||||||||||
Revenues | $ | 2,568 | $ | 1,779 | $ | 789 | $ | 5,114 | $ | 4,045 | $ | 1,069 | |||||||||||
Cost of products sold | 1,981 | 1,263 | 718 | 3,927 | 2,970 | 957 | |||||||||||||||||
Segment margin | 587 | 516 | 71 | 1,187 | 1,075 | 112 | |||||||||||||||||
Unrealized (gains) losses on commodity risk management activities | 13 | (4 | ) | 17 | — | (54 | ) | 54 | |||||||||||||||
Operating expenses, excluding non-cash compensation expense | (141 | ) | (125 | ) | (16 | ) | (280 | ) | (252 | ) | (28 | ) | |||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (17 | ) | (17 | ) | — | (35 | ) | (36 | ) | 1 | |||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 19 | 18 | 1 | 40 | 35 | 5 | |||||||||||||||||
Other | — | — | — | — | 1 | (1 | ) | ||||||||||||||||
Segment Adjusted EBITDA | $ | 461 | $ | 388 | $ | 73 | $ | 912 | $ | 769 | $ | 143 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
Fractionators and Refinery services margin | $ | 128 | $ | 117 | $ | 11 | $ | 262 | $ | 237 | $ | 25 | |||||||||||
Transportation margin | 290 | 241 | 49 | 556 | 474 | 82 | |||||||||||||||||
Storage margin | 48 | 53 | (5 | ) | 104 | 110 | (6 | ) | |||||||||||||||
Terminal Services margin | 91 | 81 | 10 | 185 | 168 | 17 | |||||||||||||||||
Marketing margin | 43 | 20 | 23 | 80 | 32 | 48 | |||||||||||||||||
Unrealized gains (losses) on commodity risk management activities | (13 | ) | 4 | (17 | ) | — | 54 | (54 | ) | ||||||||||||||
Total segment margin | $ | 587 | $ | 516 | $ | 71 | $ | 1,187 | $ | 1,075 | $ | 112 |
• | an increase of $49 million in transportation margin due to a $43 million increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines, an $11 million increase resulting from a reclassification between our transportation and fractionation margins, a $4 million increase due to higher throughput on Mariner West and a $2 million increase on Mariner South primarily due to system downtime in the prior period. These increases were partially offset by an $11 million decrease resulting from lower throughput on Mariner East 1 due to system downtime in the second quarter of 2018; |
• | an increase of $23 million in marketing margin (excluding a net change of $17 million in unrealized gains and losses) due to gains of $10 million from our butane blending operations, a $9 million increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex and a $4 million increase from optimizing sales of purity product from our Mont Belvieu fractionators; |
• | an increase of $11 million in fractionation and refinery services margin due to a $14 million increase resulting from higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility, a $6 million increase from blending gains as a result of improved market pricing and a $2 million increase from Mariner South as more cargoes were loaded at Mariner South. These increases were partially offset by an $11 million decrease resulting from a reclassification between our transportation and fractionation margins; and |
• | an increase of $10 million in terminal services margin due to a $7 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018 and a $5 million increase at our Nederland terminal due to increased demand for propane exports. These increases were partially offset by a $2 million decrease due to the effect of Mariner East pipeline system downtime on our Marcus Hook Industrial Complex; partially offset by |
• | an increase of $16 million in operating expenses primarily due to a $7 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, a $4 million increase in utilities and ad valorem taxes on the fractionators, and a $3 million increase in overhead costs; and |
• | a decrease of $5 million in storage margin primarily due to the expiration and amendments to various NGL and refined products storage contracts. |
• | an increase of $82 million in transportation margin due to $78 million from increased producer volumes from the Permian region on our Texas NGL pipelines, an $11 million increase due to higher throughput on Mariner West driven by end user facility constraints in the prior period, an $11 million increase resulting from a reclassification between our transportation and fractionation margins, a $3 million increase on Mariner South primarily due to system downtime in the prior period and a $4 million increase from higher deficiency fees. These increases were partially offset by a $17 million decrease resulting |
• | an increase of $48 million in marketing margin (excluding a net change of $54 million in unrealized gains and losses) due to an $18 million increase from our butane blending operations, a $17 million increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex and a $13 million increase from optimizing sales of purity product from our Mont Belvieu fractionators; |
• | an increase of $25 million in fractionation and refinery services margin due to a $23 million increase resulting from higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility, a $9 million increase from blending gains as a result of improved market pricing and a $4 million increase as we loaded more cargoes at our Mariner South export facility. These increases were partially offset by an $11 million decrease resulting from a reclassification between our transportation and fractionation margins; |
• | an increase of $17 million in terminal services margin due to a $18 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018 and a $6 million increase at our Nederland terminal due to increased demand for propane exports. These increases were partially offset by a $4 million decrease due to the effect of Mariner East pipeline system downtime on our Marcus Hook Industrial Complex and a $3 million decrease from our marketing terminal volumes primarily due to the sale of one of our terminals in April 2017; and |
• | an increase of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to improved contributions from our unconsolidated refined products joint venture interests; partially offset by |
• | an increase of $28 million in operating expenses due to a $18 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, a $6 million increases in certain allocated overhead and a $4 million increase in utilities and ad valorem taxes on the fractionators; and |
• | a decrease of $6 million in storage margin due to a $8 million decrease from the expiration and amendments to various NGL and refined products storage contracts and a $4 million decrease from the expiration of a fixed fee transport agreement in 2017. These increases were partially offset by a $6 million increase from throughput fees collected at our Mont Belvieu storage terminal and increased demand on the Explorer Pipeline. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
Crude transportation volumes (MBbls/d) | 4,242 | 3,452 | 790 | 4,036 | 3,248 | 788 | |||||||||||||||||
Crude terminals volumes (MBbls/d) | 2,103 | 1,950 | 153 | 2,022 | 1,864 | 158 | |||||||||||||||||
Revenues | $ | 4,803 | $ | 2,465 | $ | 2,338 | $ | 8,548 | $ | 5,040 | $ | 3,508 | |||||||||||
Cost of products sold | 4,361 | 2,091 | 2,270 | 7,538 | 4,394 | 3,144 | |||||||||||||||||
Segment margin | 442 | 374 | 68 | 1,010 | 646 | 364 | |||||||||||||||||
Unrealized losses (gains) on commodity risk management activities | 262 | (2 | ) | 264 | 305 | (2 | ) | 307 | |||||||||||||||
Operating expenses, excluding non-cash compensation expense | (144 | ) | (114 | ) | (30 | ) | (271 | ) | (186 | ) | (85 | ) | |||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (20 | ) | (32 | ) | 12 | (42 | ) | (49 | ) | 7 | |||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 8 | 2 | 6 | 10 | 6 | 4 | |||||||||||||||||
Segment Adjusted EBITDA | $ | 548 | $ | 228 | $ | 320 | $ | 1,012 | $ | 415 | $ | 597 |
• | an increase of $332 million in segment margin (excluding unrealized losses on commodity risk management activities) due to a $193 million increase resulting primarily from placing our Bakken pipeline in service in the second quarter of 2017 as well as a $27 million increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets; a $100 million increase (excluding a net change of $264 million in unrealized gains and losses) from our crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets; and a $9 million increase in terminal fees primarily from ship loading fees at our Nederland facility as a result of increased exports; |
• | a decrease of $12 million in selling, general and administrative expenses primarily due to higher professional fees recorded in the prior period; and |
• | an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates due to a new contract at one of our joint ventures; partially offset by |
• | an increase of $30 million in operating expenses due to a $13 million increase primarily resulting from placing our Bakken pipeline in service in the second quarter of 2017; a $3 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a $14 million increase from existing transportation assets due to increases of $7 million in utilities, $5 million in expense projects, $5 million in ad valorem taxes and $5 million in management fees, partially offset by decreases in environmental fees of $5 million and capacity leases of $3 million. |
• | an increase of $671 million in segment margin (excluding unrealized losses on commodity risk management activities) due to a $417 million increase resulting primarily from placing our Bakken pipeline in service in the second quarter of 2017; a $50 million increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets; a $188 million increase (excluding a net change of $307 million in unrealized gains and losses) from our crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets; and a $16 million increase primarily from our Nederland facility due to higher ship loading fees as a result of increased exports; |
• | a decrease of $7 million in selling, general and administrative expenses due to a $13 million decrease in professional fees, partially offset by an increase of $6 million related to Bakken insurance and management fees; and |
• | an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to a new contract at one of our joint ventures; partially offset by |
• | an increase of $85 million in operating expenses due to a $39 million increase primarily resulting from placing our Bakken pipeline in service in the second quarter of 2017; a $15 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a $31 million increase from existing transportation assets due to increases of $10 million in ad valorem taxes, $9 million in management fees, $8 million in utilities, $5 million in expense projects and $5 million in freight, partially offset by decreases in environmental fees of $5 million and capacity leases of $1 million. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | Change | 2018 | 2017 | Change | ||||||||||||||||||
Revenues | $ | 502 | $ | 870 | $ | (368 | ) | $ | 1,073 | $ | 1,640 | $ | (567 | ) | |||||||||
Cost of products sold | 445 | 794 | (349 | ) | 921 | 1,462 | (541 | ) | |||||||||||||||
Segment margin | 57 | 76 | (19 | ) | 152 | 178 | (26 | ) | |||||||||||||||
Unrealized (gains) losses on commodity risk management activities | (2 | ) | (4 | ) | 2 | 2 | (17 | ) | 19 | ||||||||||||||
Operating expenses, excluding non-cash compensation expense | (10 | ) | (31 | ) | 21 | (41 | ) | (52 | ) | 11 | |||||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (19 | ) | (27 | ) | 8 | (37 | ) | (48 | ) | 11 | |||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 62 | 76 | (14 | ) | 88 | 156 | (68 | ) | |||||||||||||||
Other and eliminations | 2 | 17 | (15 | ) | — | 13 | (13 | ) | |||||||||||||||
Segment Adjusted EBITDA | $ | 90 | $ | 107 | $ | (17 | ) | $ | 164 | $ | 230 | $ | (66 | ) |
• | our equity method investment in limited partnership units of Sunoco LP consisting of 26.2 million and 43.5 million Sunoco LP common units, representing 31.8% and 43.7% of Sunoco LP’s total outstanding common units as of June 30, 2018 and June 30, 2017, respectively. In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million; |
• | our natural gas marketing and compression operations. Subsequent to our contribution of CDM to USAC in April 2018, our all other segment includes our equity method investment in USAC consisting of 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests; |
• | a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and |
• | our investment in coal handling facilities. |
• | a decrease of $44 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in Sunoco LP resulting from the Partnership’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018; and |
• | a decrease of $12 million due to the contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by |
• | a decrease of $14 million in merger and acquisition expenses related to the Sunoco Logistics merger in 2017, partially offset by the CDM Contribution in 2018; |
• | an increase of $12 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES; |
• | an increase of $6 million from gains in power trading activities; and |
• | an increase of $2 million in margin due to the expiration of a capacity contract commitment. |
• | a decrease of $69 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in Sunoco LP resulting from the Partnership’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018; |
• | a decrease of $18 million in Adjusted EBITDA related to unconsolidated affiliates primarily from our investment in PES; and |
• | a decrease of $9 million due to the contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by |
• | a decrease of $17 million in merger and acquisition expenses related to the Sunoco Logistics merger in 2017, partially offset by the CDM Contribution in 2018; |
• | an increase of $8 million from commodity trading activities; and |
• | an increase of $5 million in margin from the expiration of a capacity contract commitment. |
Growth | Maintenance | ||||||||||||||
Low | High | Low | High | ||||||||||||
Intrastate transportation and storage | $ | 275 | $ | 300 | $ | 30 | $ | 35 | |||||||
Interstate transportation and storage (1) | 500 | 550 | 115 | 120 | |||||||||||
Midstream | 850 | 875 | 120 | 130 | |||||||||||
NGL and refined products transportation and services | 2,350 | 2,500 | 60 | 70 | |||||||||||
Crude oil transportation and services (1) | 450 | 475 | 90 | 100 | |||||||||||
All other (including eliminations) | 75 | 100 | 60 | 65 | |||||||||||
Total capital expenditures | $ | 4,500 | $ | 4,800 | $ | 475 | $ | 520 |
(1) | Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects. |
Capital Expenditures Recorded During Period | |||||||||||
Growth | Maintenance | Total | |||||||||
Intrastate transportation and storage | $ | 195 | $ | 21 | $ | 216 | |||||
Interstate transportation and storage | 351 | 37 | 388 | ||||||||
Midstream | 448 | 65 | 513 | ||||||||
NGL and refined products transportation and services | 974 | 26 | 1,000 | ||||||||
Crude oil transportation and services | 205 | 21 | 226 | ||||||||
All other (including eliminations) | 68 | 34 | 102 | ||||||||
Total capital expenditures | $ | 2,241 | $ | 204 | $ | 2,445 |
• | $1.00 billion aggregate principal amount of 4.875% senior notes due 2023; |
• | $800 million aggregate principal amount of 5.50% senior notes due 2026; and |
• | $400 million aggregate principal amount of 5.875% senior notes due 2028. |
June 30, 2018 | December 31, 2017 | ||||||
ETP Senior Notes (1)(2) | $ | 29,354 | $ | 27,005 | |||
Transwestern Senior Notes | 575 | 575 | |||||
Panhandle Senior Notes | 386 | 785 | |||||
Credit facilities and commercial paper: | |||||||
ETP $4.00 billion Revolving Credit Facility due December 2022 (3) | 1,228 | 2,292 | |||||
ETP $1.00 billion 364-Day Credit Facility due November 2018 | — | 50 | |||||
Bakken Project $2.50 billion Credit Facility due August 2019 | 2,500 | 2,500 | |||||
Other long-term debt | 4 | 5 | |||||
Unamortized premiums, net of discounts and fair value adjustments | 39 | 61 | |||||
Deferred debt issuance costs | (190 | ) | (179 | ) | |||
Total debt | 33,896 | 33,094 | |||||
Less: current maturities of long-term debt | 155 | 407 | |||||
Long-term debt, less current maturities | $ | 33,741 | $ | 32,687 |
(1) | Includes $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018 that were classified as long-term as of June 30, 2018 as they were refinanced on a long-term basis in June 2018, see “ETP Senior Notes Offering and Redemption” below. |
(2) | Includes $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019 and $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019 that were classified as long-term as of June 30, 2018 as management has the intent and ability to refinance the borrowings on a long-term basis. |
(3) | Includes $1.23 billion and $2.01 billion of commercial paper outstanding at June 30, 2018 and December 31, 2017, respectively. |
• | $500 million aggregate principal amount of 4.20% senior notes due 2023; |
• | $1.00 billion aggregate principal amount of 4.95% senior notes due 2028; |
• | $500 million aggregate principal amount of 5.80% senior notes due 2038; and |
• | $1.00 billion aggregate principal amount of 6.00% senior notes due 2048. |
• | ETP’s $650 million aggregate principal amount of 2.50% senior notes due June 15, 2018; |
• | Panhandle’s $400 million aggregate principal amount of 7.00% senior notes due June 15, 2018; and |
• | ETP’s $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018. |
Quarter Ended | Record Date | Payment Date | Rate | |||||
December 31, 2017 | February 8, 2018 | February 14, 2018 | $ | 0.5650 | ||||
March 31, 2018 | May 7, 2018 | May 15, 2018 | 0.5650 | |||||
June 30, 2018 | August 6, 2018 | August 14, 2018 | 0.5650 |
Period Ended | Record Date | Payment Date | Rate | |||||
Series A Preferred Units | ||||||||
December 31, 2017 | February 1, 2018 | February 15, 2018 | $ | 15.451 | ||||
June 30, 2018 | August 1, 2018 | August 15, 2018 | 31.250 | |||||
Series B Preferred Units | ||||||||
December 31, 2017 | February 1, 2018 | February 15, 2018 | $ | 16.378 | ||||
June 30, 2018 | August 1, 2018 | August 15, 2018 | 33.125 | |||||
Series C Preferred Units | ||||||||
June 30, 2018 | August 1, 2018 | August 15, 2018 | $ | 0.56337 |
Six Months Ended June 30, | |||||||
2018 | 2017 | ||||||
Limited Partners: | |||||||
Common Units held by public | $ | 1,286 | $ | 1,156 | |||
Common Units held by ETE | 31 | 30 | |||||
General Partner interest and incentive distributions held by ETE | 900 | 781 | |||||
IDR relinquishments | (84 | ) | (319 | ) | |||
Series A Preferred Units | 30 | — | |||||
Series B Preferred Units | 18 | — | |||||
Series C Preferred Units | 10 | — | |||||
Total distributions declared to partners | $ | 2,191 | $ | 1,648 |
Year Ending December 31, | ||||
2018 (remainder) | $ | 69 | ||
2019 | 128 | |||
Each year beyond 2019 | 33 |
June 30, 2018 | December 31, 2017 | ||||||||||||||||||||
Notional Volume | Fair Value Asset (Liability) | Effect of Hypothetical 10% Change | Notional Volume | Fair Value Asset (Liability) | Effect of Hypothetical 10% Change | ||||||||||||||||
Mark-to-Market Derivatives | |||||||||||||||||||||
(Trading) | |||||||||||||||||||||
Natural Gas (BBtu): | |||||||||||||||||||||
Fixed Swaps/Futures | 465 | $ | — | $ | — | 1,078 | $ | — | $ | — | |||||||||||
Basis Swaps IFERC/NYMEX (1) | 102,328 | 3 | — | 48,510 | 2 | 1 | |||||||||||||||
Options – Puts | (3,043 | ) | — | — | 13,000 | — | — | ||||||||||||||
Power (Megawatt): | |||||||||||||||||||||
Forwards | 3,196,100 | 12 | 8 | 435,960 | 1 | 1 | |||||||||||||||
Futures | (42,768 | ) | — | — | (25,760 | ) | — | — | |||||||||||||
Options – Puts | (30,532 | ) | 1 | — | (153,600 | ) | — | 1 | |||||||||||||
Options – Calls | 996,172 | — | 1 | 137,600 | — | — | |||||||||||||||
Crude (MBbls) – Futures | — | — | — | — | 1 | — | |||||||||||||||
(Non-Trading) | |||||||||||||||||||||
Natural Gas (BBtu): | |||||||||||||||||||||
Basis Swaps IFERC/NYMEX | 6,600 | (50 | ) | 18 | 4,650 | (13 | ) | 4 | |||||||||||||
Swing Swaps IFERC | 52,413 | (1 | ) | — | 87,253 | (2 | ) | 1 | |||||||||||||
Fixed Swaps/Futures | 5,360 | (2 | ) | 3 | (4,700 | ) | (1 | ) | 2 | ||||||||||||
Forward Physical Contracts | (174,465 | ) | 4 | — | (145,105 | ) | 6 | 41 | |||||||||||||
NGL (MBbls) – Forwards/Swaps | (1,590 | ) | (16 | ) | 11 | (2,493 | ) | 5 | 16 | ||||||||||||
Crude (MBbls) – Forwards/Swaps | 44,190 | (307 | ) | 261 | 9,172 | (4 | ) | 9 | |||||||||||||
Refined Products (MBbls) – Futures | (1,076 | ) | (5 | ) | 5 | (3,783 | ) | (25 | ) | 4 | |||||||||||
Fair Value Hedging Derivatives | |||||||||||||||||||||
(Non-Trading) | |||||||||||||||||||||
Natural Gas (BBtu): | |||||||||||||||||||||
Basis Swaps IFERC/NYMEX | (21,475 | ) | (1 | ) | — | (39,770 | ) | (2 | ) | — | |||||||||||
Fixed Swaps/Futures | (21,475 | ) | (1 | ) | 7 | (39,770 | ) | 14 | 11 |
(1) | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Term | Type(1) | Notional Amount Outstanding | ||||||||
June 30, 2018 | December 31, 2017 | |||||||||
July 2018(2) | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | $ | — | $ | 300 | |||||
July 2019(2) | Forward-starting to pay a fixed rate of 3.56% and receive a floating rate | 400 | 300 | |||||||
July 2020(2) | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | 400 | 400 | |||||||
July 2021(2) | Forward-starting to pay a fixed rate of 3.55% and receive a floating rate | 400 | — | |||||||
December 2018 | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | 1,200 | 1,200 | |||||||
March 2019 | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | 300 | 300 |
(1) | Floating rates are based on 3-month LIBOR. |
(2) | Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. |
• | changes in ETE’s and ETP’s business, operations and prospects; |
• | changes in market assessments of ETE’s and ETP’s business, operations and prospects; |
• | interest rates, general market, industry and economic conditions and other factors generally affecting the price of ETE common units; and |
• | federal, state and local legislation, governmental regulation and legal developments in the businesses in which ETE and ETP operate. |
• | any resolution or course of action by ETP GP or its affiliates in respect of a conflict of interest is permitted and deemed approved by all partners of ETP (i.e. the ETP unitholders), and will not constitute a breach of the ETP partnership agreement or of any duty stated or implied by law or equity, if the resolution or course of action is approved by Special Approval or unaffiliated ETP unitholder approval; and |
• | ETP GP may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants selected by it, and any act taken or omitted to be taken in reliance upon the opinion of such persons as to matters that ETP GP reasonably believes to be within such person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion. |
• | the parties may be liable for damages to one another under the terms and conditions of the merger agreement; |
• | negative reactions from the financial markets, including declines in the price of ETE common units or ETP common units due to the fact that current prices may reflect a market assumption that the merger will be completed; |
• | having to pay certain significant costs relating to the merger, including, in certain circumstances, the reimbursement by ETP of up to $30 million of ETE’s expenses and a termination fee of $750 million less any previous expense reimbursements by ETP; and |
• | the attention of management of ETE and ETP will have been diverted to the merger rather than other strategic opportunities that could have been beneficial to that organization. |
Exhibit Number | Description | |
101.INS* | XBRL Instance Document | |
101.SCH* | XBRL Taxonomy Extension Schema Document | |
101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB* | XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith. | |
** | Furnished herewith. | |
*** | Denotes a management contract or compensatory plan or arrangement. Filed herewith. |
ENERGY TRANSFER PARTNERS, L.P. | |||
By: | Energy Transfer Partners GP, L.P. | ||
its General Partner | |||
By: | Energy Transfer Partners, L.L.C. | ||
its General Partner | |||
Date: | August 9, 2018 | By: | /s/ A. Troy Sturrock |
A. Troy Sturrock | |||
Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant) |
AMENDED AND RESTATED | ||||
ENERGY TRANSFER PARTNERS, L.L.C. | ||||
ANNUAL BONUS PLAN | ||||
1. | Purpose. The purpose of this Plan is to motivate management and the employees who perform services for the Partnership and/or its affiliates and subsidiaries to earn annual cash awards through the achievement of performance and target goals. |
2. | Definitions. As used in this Plan, the following terms shall have the meanings herein specified: |
2.1 | Actual Results means the dollar amount of Adjusted EBITDA, Distributable Cash Flow, Departmental Budget or other applicable financial measure specified for the Budget Target(s) for a Plan Year actually achieved for such Plan Year as determined by the Partnership following the end of such Plan Year. |
2.2 | Adjusted EBITDA means earnings before interest, taxes, depreciation and amortization adjusted for non-cash compensation and extraordinary costs, including but not limited to transactional costs. |
2.3 | Annual Bonus means the cash bonus paid to an Eligible Employee for the Plan Year. |
2.4 | Annual Target Bonus means, for an Eligible Employee, a percentage of such Eligible Employee’s Eligible Earnings, and shall be dependent on a number of factors which may include but are not limited to an employee’s position title, job responsibilities, and reporting level within the Company. The Company may, but is not required to, specify a specific range for an Eligible Employee at any time prior to or during a Plan Year; provided that any such range may be adjusted from time to time or at any time in the Company’s sole discretion, including for the applicable Plan Year. |
2.5 | Annual Target Bonus Pool means, for a Plan Year, the Target Bonus of the Eligible Employees of the Company for that Plan Year. |
2.6 | Board means the Board of Directors of the Company. |
2.7 | Bonus Pool Payout Factor means the multiplier factor applied to the Annual Target Bonus Pool to determine the Funded Bonus Pool for the applicable Plan Year. The payout is determined by the comparison of the Budget Target(s) for the Plan Year to Actual Results. General guidelines for the Budget Target and the Bonus Pool Payout Factor associated with such Budget Target for a Plan Year are set forth below, but each are subject to the sole discretion of the Compensation Committee. The Bonus Pool Payout Factor for purposes of the Plan shall be adjusted each Plan Year based on the specific allocation of Annual Target Bonus Pools to each of the specified Budget Target(s). Such allocations of each Budget Target to the total Annual Bonus Pool shall be determined on an annual basis by the Compensation Committee. For 2018, the Adjusted EBITDA Budget Target shall comprise 60% of the total Annual Target Bonus Pool, the Distributable Cash Flow Budget Target shall comprise 20% of the total Annual Target Bonus Pool and the Departmental Budget Target shall comprise the remaining 20% of the total Annual Target Bonus Pool. While the Funded Bonus Pool will reflect an aggregation of performance under each Bonus Pool Payout Factor the performance of Adjusted EBITDA Budget Target shall drive calculation of the Bonus Pool, as no other targets shall be considered unless the Adjusted EBITDA Target results is at least 80% of its Budget Target. |
% of Budget Target | Bonus Pool Payout Factor |
>=110.0 | 1.20x |
109.9 – 105.0 | 1.10x |
104.9 – 95.0 | 1.00x |
94.9 – 90.0 | .90x |
89.9 – 80.0 | .75x |
< 80.0 | .0x |
% of Budget Target | Bonus Pool Payout Factor |
>=110.0 | 1.20x |
109.9 – 105.0 | 1.10x |
104.9 – 95.0 | 1.00x |
94.9 – 90.0 | .90x |
89.9 – 80.0 | .75x |
< 80.0 | .0x |
% of Budget Target | Bonus Pool Payout Factor |
0.0-100.9 | 1.00x |
101.0-105.9 | .90x |
106.0 – 110.9 | .70x |
111.0-114.9 | .50x |
>115 | .0x |
2.8 | Budget Target means the specific dollar amount of Adjusted EBITDA, Distributable Cash Flow, total Departmental Budget and/or other financial measure(s) established by the Compensation Committee for the Company for a Plan Year. |
2.9 | Company means Energy Transfer Partners, L.L.C., a Delaware limited liability company. The term “Company” shall include any successor to Energy Transfer |
2.10 | Compensation Committee means the Compensation Committee of the Company’s Board. |
2.11 | Departmental Budget means the specific dollar amount of general and administrative expenses (i.e. operating budget) or operating and maintenance expenses set for each department of Partnership and its subsidiaries. In the case where a department head oversees multiple departments the Departmental Budget shall be the total aggregate budget for all of his/her departments. |
2.12 | Distributable Cash Flow means net income, adjusted for certain non-cash items, less maintenance capital expenditures. |
2.13 | Eligible Earnings means the aggregate regular earnings plus overtime earnings, if any, received by an Eligible Employee during the Plan Year. For the avoidance of doubt, neither distribution payments or distribution equivalent payments on any Partnership restricted or common units nor any other bonus or sign-on payments received by an Eligible Employee during the Plan Year shall be included in the calculation of Eligible Earnings for an Eligible Employee. |
2.14 | Eligible Employee has the meaning set forth in Section 4 below. |
2.15 | Funded Bonus Pool means the Annual Target Bonus Pool for a Plan Year multiplied by the applicable Bonus Pool Payout Factor for such Plan Year. The establishment and amount of a Funded Bonus Pool is 100% discretionary and subject to the final approval of and/or adjustment by the Compensation Committee. |
2.16 | Operational Safety Standards means the safety standards, training and requirements set forth on Exhibit A hereto, which operations based Eligible Employees are required to comply. |
2.17 | Partnership means Energy Transfer Partners L.P., a Delaware master limited partnership. |
2.18 | Person means an individual, corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity. |
2.19 | Plan means the Company’s Annual Bonus Plan as set forth herein, as the same may be amended from time to time. |
2.20 | Plan Year means the performance (calendar) year for the measurement and determination of the Budget Target and the calculation of Actual Results. Unless otherwise determined by the Compensation Committee, each Plan Year shall be the one year period commencing on January 1 and ending on December 31 of the calendar year. |
3. | Plan Guidelines and Administration. The administration of the Plan and any potential Annual Bonus awarded pursuant to the Plan are subject to the sole determination and discretion of the Compensation Committee. The Compensation Committee will review the Partnership’s performance results for the designated Plan Year, the Budget Target and Bonus Pool Payout |
4. | Eligible Employees. Subject to the discretion of the Compensation Committee and such other criteria as may be established by the Compensation Committee in general or for a particular Plan Year, all regular full-time employees providing services to the Partnership and its subsidiaries are eligible to participate in the Annual Target Bonus Pool for a Plan Year. No Eligible Employee shall be entitled to receive an Annual Bonus for a Plan Year unless he or she is actively employed by the Company (or one of its Affiliates) on the date the Annual Bonus for such Plan Year is paid by the Company even if such payment date is after the Plan Year. |
5. | Annual Bonus Payments for Eligible Employees. As soon as reasonably practicable following the end of the Plan Year, management of the Company will determine the Annual Target Bonus for each Eligible Employee. The Funded Bonus Pool from which Annual Bonuses are paid to Eligible Employees shall equal (a) the aggregate of the Annual Target Bonuses of all Eligible Employees multiplied by (b) the Bonus Pool Payout Factor for such Plan Year, as determined by the Compensation Committee after review of the performance results for the Plan year. The amount of the Annual Bonus for an Eligible Employee from the Funded Bonus Pool shall be determined in management’s sole discretion and shall be based on a number of factors including an employee’s performance, length of employment and such other factors as may be determined by management in its sole discretion, which factors may not be the same fall all Eligible Employees. Notwithstanding the foregoing, the Compensation Committee shall make determination of the Annual Bonus of all of the Company’s named executive officers and such other executive officers as may be determined from time to time. |
6. | Amendment and Termination. The Compensation Committee, at its sole discretion, may, without prior notice to or consent of any Eligible Employees, amend the Plan or terminate the Plan at any time and at all times. |
7. | Indemnification. Neither the Company, any participating Affiliate, nor the Board, or the Compensation Committee, of the Company or any participating affiliate, nor any officer or employee of the Company or any participating affiliate shall be liable for any act, omission, interpretation, construction or determination made in connection with the Plan in good faith; and the members of the Company’s Board, the Compensation Committee and/or management of the Company shall be entitled to indemnification and reimbursement by the Company to the maximum extent permitted by law in respect of any claim, loss, damage or expense (including counsel’s fees) arising from their acts, omission and conduct in their official capacity with respect to the Plan. |
8. | General provisions. |
8.1 | Non-Guarantee of Employment or Participation in the Plan. Nothing contained in this Plan shall be construed as a contract of employment between the Company, the Partnership and/or any of its affiliates and any employee of the Company or any of its affiliates, and nothing in this Plan shall confer upon any employee, including an Eligible Employee, any right to continued employment with the Company and/or its affiliate, or interfere with the right of the Company, the Partnership and/or its affiliate to terminate the employment, with or without cause, of an employee, including an Eligible Employee. Nothing in this Plan shall give any employee any right to participate in the Plan and/or to receive an Annual Bonus with respect to any Plan Year. |
8.2 | Interests Not Transferable. No right, interest or benefit under the Plan shall be subject in any manner to alienation, sale, transfer, assignment, pledge, attachment or other legal process, or encumbrance of any kind, and any attempt to do so shall be void. |
8.3 | Controlling Law. To the extent not superseded by federal law, the law of the State of Texas, without regard to the conflicts of laws provisions thereunder, shall be controlling in all matters relating to the Plan. |
8.4 | Severability. If any Plan provision or any Annual Bonus award hereunder is or becomes or is deemed to be invalid, illegal, or unenforceable in any jurisdiction or as to any person or award, or would disqualify the Plan or any award under the law deemed applicable by the Compensation Committee, such provision shall be construed or deemed amended to conform to the applicable laws, or if it cannot be construed or deemed amended without, in the determination of the Compensation Committee, materially altering the intent of the Plan or the award, such provision shall be stricken as to such jurisdiction, person or award and the remainder of the Plan and any such award shall remain in full force and effect. |
8.5 | No Trust or Fund Created. Neither the Plan nor any award shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Company and its Affiliates and an employee, including an Eligible Employee or any other person. The Plan shall constitute an unfunded mechanism for the Company to pay bonus compensation to participants from its general assets. No participant shall have any security or other interest in the assets of the Company. |
8.6 | Headings. Headings are given to the sections of the Plan solely as a convenience to facilitate reference. Such headings shall not be deemed in any way material or relevant to the construction or interpretation of the Plan or any provision of it. |
8.7 | Tax Withholding. The Company and/or any participating Affiliate may deduct from any payment otherwise due under this Plan to a Participant (or beneficiary) amounts required by law to be withheld for purposes of federal, state or local taxes. |
8.8 | Off-set. The Company reserves the right to withhold any or all portions of an award or to reduce an award to a participant up to an amount equal to any amount the participant owes to the Company or any of its Affiliates. |
8.9 | Effective Date. This Plan was effective for the Plan Year commencing on January 1, 2014 and was amended and restated effective for the Plan year commencing on January 1, 2018. |
1. | Satisfactory completion of all required safety training and instruction |
2. | Attendance at all required safety meetings |
3. | Avoidance of preventable vehicle incidents |
4. | Management discretion of overall compliance and understanding of safety standards and requirements for operation |
Six Months Ended June 30, 2018 | |||||||
Energy Transfer Partners, L.P. (consolidated) | Sunoco Logistics Partners Operations L.P. | ||||||
Fixed Charges: | |||||||
Interest expense, net | $ | 704 | $ | 81 | |||
Capitalized interest | 160 | 106 | |||||
Interest charges included in rental expense | 4 | 2 | |||||
Total fixed charges | 868 | 189 | |||||
Series A, B and C preferred unit distributions | 54 | — | |||||
Total fixed charges and preferred unit distributions | 922 | 189 | |||||
Earnings: | |||||||
Income before income tax expense | 1,510 | 278 | |||||
Less: equity in earnings of unconsolidated affiliates | 34 | 91 | |||||
Total earnings | 1,476 | 187 | |||||
Add: | |||||||
Fixed charges | 868 | 189 | |||||
Amortization of capitalized interest | 11 | 2 | |||||
Distributed income of equity investees | 215 | 79 | |||||
Less: | |||||||
Interest capitalized | (160 | ) | (106 | ) | |||
Income available for fixed charges | $ | 2,410 | $ | 351 | |||
Ratio of earnings to fixed charges | 2.78 | 1.86 | |||||
Ratio of earnings to fixed charges and preferred unit distributions | 2.61 | 1.86 |
1. | I have reviewed this quarterly report on Form 10-Q of Energy Transfer Partners, L.P.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
/s/ Kelcy L. Warren |
Kelcy L. Warren |
Chief Executive Officer |
1. | I have reviewed this quarterly report on Form 10-Q of Energy Transfer Partners, L.P.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
/s/ Thomas E. Long |
Thomas E. Long |
Chief Financial Officer |
(1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. |
/s/ Kelcy L. Warren |
Kelcy L. Warren |
Chief Executive Officer |
(1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. |
/s/ Thomas E. Long |
Thomas E. Long |
Chief Financial Officer |
Document And Entity Information - shares |
6 Months Ended | |
---|---|---|
Jun. 30, 2018 |
Aug. 03, 2018 |
|
Entity Information [Abstract] | ||
Entity Registrant Name | Energy Transfer Partners, L.P. | |
Entity Central Index Key | 0001161154 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 1,166,403,685 | |
Document Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2018 | |
Document Fiscal Year Focus | 2018 | |
Document Fiscal Period Focus | Q2 |
Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | |||
Statement of Comprehensive Income [Abstract] | ||||||||
Net income | $ 602 | $ 296 | $ 1,481 | $ 689 | ||||
Other comprehensive income (loss), net of tax: | ||||||||
Change in value of available-for-sale securities | 0 | 1 | (2) | 3 | ||||
Actuarial loss relating to pension and other postretirement benefit plans | 0 | (1) | (2) | (3) | ||||
Change in other comprehensive income from unconsolidated affiliates | 2 | (1) | 7 | (1) | ||||
Total other comprehensive income (loss) | 2 | (1) | 3 | (1) | ||||
Comprehensive income | 604 | 295 | 1,484 | 688 | ||||
Less: Comprehensive income attributable to noncontrolling interest | 170 | 94 | 334 | 156 | ||||
Comprehensive income attributable to partners | $ 434 | $ 201 | $ 1,150 | $ 532 | ||||
|
Consolidated Statement Of Equity - 6 months ended Jun. 30, 2018 - USD ($) $ in Millions |
Total |
Series A Preferred Units [Member] |
Series B Preferred Units [Member] |
Series C Preferred Units [Member] |
Common Units |
General Partner |
Accumulated Other Comprehensive Income (Loss) |
Noncontrolling Interest |
---|---|---|---|---|---|---|---|---|
Balance, December 31, 2017 at Dec. 31, 2017 | $ 34,151 | $ 944 | $ 547 | $ 0 | $ 26,531 | $ 244 | $ 3 | $ 5,882 |
Distributions to partners | (2,011) | (15) | (9) | 0 | (1,315) | (672) | 0 | 0 |
Distributions to noncontrolling interest | (359) | 0 | 0 | 0 | 0 | 0 | 0 | (359) |
Units issued for cash | 475 | 0 | 0 | 436 | 39 | 0 | 0 | 0 |
Capital contributions from noncontrolling interest | 318 | 0 | 0 | 0 | 0 | 0 | 0 | 318 |
Repurchases of common units | (24) | 0 | 0 | 0 | (24) | 0 | 0 | 0 |
Other comprehensive income, net of tax | 3 | 0 | 0 | 0 | 0 | 0 | 3 | 0 |
Other, net | 2 | 1 | 0 | 0 | 26 | 17 | (2) | (4) |
Net income | 1,481 | 30 | 18 | 6 | 289 | 804 | 0 | 334 |
Balance, June 30, 2018 at Jun. 30, 2018 | $ 34,036 | $ 958 | $ 556 | $ 442 | $ 25,546 | $ 359 | $ 4 | $ 6,171 |
Consolidated Statements Of Cash Flows - USD ($) $ in Millions |
6 Months Ended | ||||
---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | |||
OPERATING ACTIVITIES | |||||
Net income | $ 1,481 | $ 689 | |||
Reconciliation of net income to net cash provided by operating activities: | |||||
Depreciation, depletion and amortization | 1,191 | 1,117 | |||
Deferred income taxes | 52 | 121 | |||
Non-cash compensation expense | 41 | 38 | |||
Gain on Sunoco LP common unit repurchase | (172) | 0 | |||
Loss on deconsolidation of CDM | 86 | 0 | |||
Distributions on unvested awards | (17) | (15) | |||
Equity in earnings of unconsolidated affiliates | (34) | (12) | |||
Distributions from unconsolidated affiliates | 215 | 197 | |||
Other non-cash | (122) | (98) | |||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | 229 | (387) | |||
Net cash provided by operating activities | 2,950 | 1,650 | |||
INVESTING ACTIVITIES | |||||
Cash proceeds from Bakken pipeline transaction | 0 | 2,000 | |||
Cash proceeds from CDM contribution | 1,227 | 0 | |||
Cash proceeds from Sunoco LP common unit repurchase | 540 | 0 | |||
Cash paid for acquisition of PennTex noncontrolling interest | 0 | (280) | |||
Cash paid for all other acquisitions | 29 | 261 | |||
Capital expenditures, excluding allowance for equity funds used during construction | (3,409) | (2,842) | |||
Contributions in aid of construction costs | 60 | 10 | |||
Contributions to unconsolidated affiliates | (13) | (225) | |||
Distributions from unconsolidated affiliates in excess of cumulative earnings | 31 | 94 | |||
Proceeds from the sale of assets | 2 | 25 | |||
Other | 0 | (7) | |||
Net cash used in investing activities | (1,591) | (1,486) | |||
FINANCING ACTIVITIES | |||||
Proceeds from borrowings | 12,476 | 11,466 | |||
Repayments of debt | (12,018) | (10,953) | |||
Cash paid to affiliate notes | 0 | (255) | |||
Common units issued for cash | 39 | 990 | |||
Preferred units issued for cash | 436 | 0 | |||
Capital contributions from noncontrolling interest | 318 | 456 | |||
Distributions to partners | (2,011) | (1,702) | |||
Distributions to noncontrolling interest | (359) | (186) | |||
Repurchases of common units | 24 | 0 | |||
Redemption of Legacy ETP Preferred Units | 0 | (53) | |||
Debt issuance costs | 38 | 20 | |||
Other | 10 | 5 | |||
Net cash used in financing activities | (1,171) | (252) | |||
Increase (decrease) in cash and cash equivalents | 188 | (88) | |||
Cash and cash equivalents, beginning of period | 306 | 360 | |||
Cash and cash equivalents, end of period | $ 494 | $ 272 | |||
|
Operations And Basis of Presentation |
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Operations And Organization [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operations And Organization | ORGANIZATION AND BASIS OF PRESENTATION Organization Energy Transfer Partners, L.P. (“ETP”) is a consolidated subsidiary of ETE. In August 2018, ETE and ETP announced that they have entered into a definitive agreement providing for the merger of ETP with a wholly-owned subsidiary of ETE in a unit-for-unit exchange. In connection with the transaction, ETE’s IDRs in ETP will be cancelled. Under the terms of the transaction, ETP unitholders (other than ETE and its subsidiaries) will receive 1.28 common units of ETE for each common unit of ETP they own. The transaction is expected to close in the fourth quarter of 2018, subject to the approval by a majority of the unaffiliated unitholders of ETP and other customary closing conditions. In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction (the “Sunoco Logistics Merger”), with the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. In connection with the Sunoco Logistics Merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes). The consolidated financial statements of the Partnership presented herein include our operating subsidiaries (collectively, the “Operating Companies”), through which our activities are primarily conducted, as follows:
We currently have the following reportable business segments: •intrastate transportation and storage; •interstate transportation and storage; •midstream; •NGL and refined products transportation and services; •crude oil transportation and services; and •all other. Prior periods have been retrospectively adjusted to reflect the impact of the Sunoco Logistics Merger on our reportable business segments. Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements of Energy Transfer Partners, L.P. for the year ended December 31, 2017, included in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 23, 2018. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. The historical common units and net income per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity. Change in Accounting Policy Inventory Accounting Change During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method. As a result of this change in accounting policy, the consolidated statement of operations and comprehensive income in prior periods have been retrospectively adjusted, as follows:
(1) As originally reported amounts reflect certain reclassifications made to conform to the current year presentation. As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows:
Revenue Recognition Standard In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018. Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to decreases in revenue (with offsetting decreases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018. The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods. The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales and operating expenses. There were no material changes in the timing of recognition of revenue and therefore no material impacts to the balance sheet upon adoption. The disclosure below shows the impact of adopting the new standard during the period of adoption compared to amounts that would have been reported under the Partnership’s previous revenue recognition policies:
Additional disclosures related to revenue are included in Note 12. Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates. Recent Accounting Pronouncements ASU 2016-02 In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840. The Partnership expects to adopt ASU 2016-02 and elect the practical expedient under ASU 2018-01 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. ASU 2017-12 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. ASU 2018-02 In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material. |
Acquisitions and Other Transactions |
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Acquisitions [Abstract] | |
Business Combination Disclosure [Text Block] | ACQUISITIONS AND OTHER INVESTING TRANSACTIONS CDM Contribution On April 2, 2018, ETP contributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019. Prior to the CDM Contribution, the CDM entities were indirect wholly-owned subsidiaries of ETP. Beginning April 2018, ETP’s consolidated financial statements reflected an equity method investment in USAC. CDM’s assets and liabilities were not reflected as held for sale, nor were CDM’s results reflected as discontinued operations in these financial statements. At June 30, 2018, the carrying value of ETP’s investment in USAC was $399 million, which is reflected in the all other segment. ETP recorded a $86 million loss on the deconsolidation of CDM including a $45 million accrual related to the indemnification of USAC related to an ongoing CDM sales and use tax audit. In connection with the CDM Contribution, ETE acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC, and (ii) 12,466,912 USAC common units for cash consideration equal to $250 million. |
Advances to and Investments in Affiliates (Notes) |
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Schedule of Equity Method Investments [Line Items] | |
Investments in and Advances to Affiliates, Schedule of Investments [Text Block] | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES HPC ETP previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, ETP acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in ETP’s financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in ETP’s financial statements. Sunoco LP In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. As of June 30, 2018, ETP owns 26.2 million Sunoco LP common units representing 31.8% of Sunoco LP’s total outstanding common units. Our investment in Sunoco LP is reflected in the all other segment. As of June 30, 2018, the carrying value of our investment in Sunoco LP is $535 million. USAC As of June 30, 2018, ETP owns 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests in USAC. USAC provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. Our investment in USAC is reflected in the all other segment. As of June 30, 2018, the carrying value of our investment in USAC is $399 million. |
Cash And Cash Equivalents |
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Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | CASH AND CASH EQUIVALENTS Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:
* As adjusted. See Note 1. Non-cash investing and financing activities are as follows:
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Cash And Cash Equivalents | Non-cash investing and financing activities are as follows:
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Inventories |
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Inventories | INVENTORIES Inventories consisted of the following:
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations. |
Fair Value Measurements |
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Fair Value Measurements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | FAIR VALUE MEASURES Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of June 30, 2018 was $33.64 billion and $33.90 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations was $34.28 billion and $33.09 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the six months ended June 30, 2018, no transfers were made between any levels within the fair value hierarchy. The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 based on inputs used to derive their fair values:
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Income (Loss) Per Limited Partner Unit [Text Block] | NET INCOME (LOSS) PER LIMITED PARTNER UNIT The historical common units and net income per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
* As adjusted. See Note 1. For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to preferred unitholders and the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period. |
Debt Obligations |
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Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Debt Obligations | DEBT OBLIGATIONS ETP Senior Notes Offering and Redemption In June 2018, ETP issued the following senior notes: •$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. The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal on the senior notes is payable upon maturity and interest is paid semi-annually. The senior notes rank equally in right of payment with ETP’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETP may incur. The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes. The $2.96 billion net proceeds from the offering were used to repay borrowings outstanding under ETP’s revolving credit facility, for general partnership purposes and to redeem all of the following senior notes: •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. The aggregate amount paid to redeem these notes was approximately $1.65 billion. Credit Facilities and Commercial Paper ETP Five-Year Credit Facility ETP’s revolving credit facility (the “ETP Five-Year Credit Facility”) allows for unsecured borrowings up to $4.00 billion and matures in December 2022. The ETP Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions. As of June 30, 2018, the ETP Five-Year Credit Facility had $1.23 billion outstanding, all of which was commercial paper. The amount available for future borrowings was $2.61 billion after taking into account letters of credit of $167 million. The weighted average interest rate on the total amount outstanding as of June 30, 2018 was 2.87%. ETP 364-Day Facility ETP’s 364-day revolving credit facility (the “ETP 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 30, 2018. As of June 30, 2018, the ETP 364-Day Facility had no outstanding borrowings. Bakken Credit Facility In August 2016, ETP and Phillips 66 completed project-level financing of the Bakken pipeline. The $2.50 billion credit facility matures in August 2019 (the “Bakken Credit Facility”). As of June 30, 2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of June 30, 2018 was 3.72%. Compliance with Our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of June 30, 2018. |
Equity |
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Equity | EQUITY The changes in outstanding common units during the six months ended June 30, 2018 were as follows:
Equity Distribution Program During the six months ended June 30, 2018, there were no units issued under the Partnership’s equity distribution agreement. As of June 30, 2018, $752 million of the Partnership’s common units remained available to be issued under the Partnership’s existing $1.00 billion equity distribution agreement. Distribution Reinvestment Program During the six months ended June 30, 2018, distributions of $39 million were reinvested under the Partnership’s distribution reinvestment plan. Preferred Units ETP issued 950,000 Series A Preferred Units and 550,000 Series B Preferred Units in November 2017. Series C Preferred Units Issuance In April 2018, ETP issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $450 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes. Distributions on the Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The Series C Preferred Units are redeemable at ETP’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Series D Preferred Units Issuance In July 2018, ETP issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $445 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes. Distributions on the Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.378% per annum. The Series D Preferred Units are redeemable at ETP’s option on or after August 15, 2023 at a redemption price of $25 per Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Cash Distributions Under our limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner. Distributions on common units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:
ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods:
Distributions on preferred units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:
Accumulated Other Comprehensive Income The following table presents the components of AOCI, net of tax:
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Income Taxes (Notes) |
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Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | INCOME TAXES The Partnership’s effective tax rate differs from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. For the three and six months ended June 30, 2018, the Partnership’s income tax benefit also reflected $3 million and $70 million, respectively, of deferred benefit adjustments as the result of a state statutory rate reduction. |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities |
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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES Guarantee of Sunoco LP Notes In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to certain of Sunoco LP’s senior notes and $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”). On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes, repaid and terminated the term loan and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes. FERC Audit In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing. Commitments In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations. Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
Litigation and Contingencies We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Dakota Access Pipeline On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access to make two crossings of the Missouri River in North Dakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE and challenged the legality of these permits and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case was pending, which the court denied on September 9, 2016. Dakota Access intervened in the case. The Cheyenne River Sioux Tribe (“CRST”) also intervened. The SRST filed an amended complaint and added claims based on treaties between the Tribes and the United States and statutes governing the use of government property. In February 2017, in response to a presidential memorandum, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. The CRST moved for a preliminary injunction and temporary restraining order (“TRO”) to block operation of the pipeline, which was denied, and raised claims based on the religious rights of the Tribe. The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes. On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court concluded that the USACE had not violated trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. On May 3, 2018, the District Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. On June 8, 2018, the USACE filed a status report stating that they will conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they will need until August 31, 2018 to finish the remand process. Following the completion of the remand process by the USACE, the Court will make a determination regarding the three discrete issues covered by the remand order. On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent third-party to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The assessment report was filed with the Court. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access filed the revised plan with the Court. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first and second reports were filed with the court on December 29, 2017 and February 28, 2018, respectfully. In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. On March 19, 2018, the District Court denied YST’s motion for partial summary judgment and instead granted judgment in favor of Dakota Access pipeline and the USACE on the claims raised in YST’s motion. The Court concluded that YST’s NHPA claims are moot because construction of the pipeline is complete and that the government’s review process did not violate NEPA or the various treaties cited by the YST. On February 8, 2018, the Court docketed a motion by CRST to “compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re remand process and remand conditions.” The motions seek an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access pipeline and the USACE opposed both motions. On April 16, 2018, the Court denied both motions. While ETP believes that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. ETP cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project. Mont Belvieu Incident On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses. MTBE Litigation Sunoco, Inc. and/or Sunoco, Inc. (R&M) (now known as Sunoco (R&M), LLC) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees. As of June 30, 2018, Sunoco, Inc. is a defendant in six cases, including one case each initiated by the States of Maryland, Vermont and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. On April 5, 2018, the Court entered an Order dismissing the matter with prejudice. It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position. Regency Merger Litigation Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency-ETP merger (the “Regency Merger”). All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (“Defendants”). The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC (the “Regency Defendants”). On March 6, 2018, the Regency Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint. Trial is currently set for September 23-27, 2019. The Regency Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger. Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. ETP’s petition for review remains under consideration by the Texas Supreme Court. Bayou Bridge On January 11, 2018, environmental groups and a trade association filed suit against the USACE in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the USACE’s issuance of permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the USACE corrects alleged deficiencies in its decision-making process. ETP, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26, 2018. On March 27, 2018, Bayou Bridge filed an answer to the complaint. On January 29, 2018, Plaintiffs filed motions for a preliminary injunction and TRO. United States District Court Judge Shelly Dick denied the TRO on January 30, 2018, but subsequently granted the preliminary injunction on February 23, 2018. On February 26, 2018, Bayou Bridge filed a notice of appeal and a motion to stay the February 23, 2018 preliminary injunction order. On February 27, 2018, Judge Dick issued an opinion that clarified her February 23, 2018 preliminary injunction order and denied Bayou Bridge’s February 26, 2018 motion to stay as moot. On March 1, 2018, Bayou Bridge filed a new notice of appeal and motion to stay the February 27, 2018 preliminary injunction order in the district court. On March 5, 2018, the district court denied the March 1, 2018 motion to stay the February 27, 2018 order. On March 2, 2018, Bayou Bridge filed a motion to stay the preliminary injunction in the Fifth Circuit. On March 15, 2018, the Fifth Circuit granted a stay of injunction pending appeal and found that Bayou Bridge “is likely to succeed on the merits of its claim that the district court abused its discretion in granting a preliminary injunction.” Oral arguments were heard on the merits of the appeal, that is, whether the district court erred in granting the preliminary injunction in the Fifth Circuit on April 30, 2018. The district court has stayed the merits case pending decision of the Fifth Circuit. On May 10, 2018, the District Court stayed the litigation pending a decision from the Fifth Circuit. On July 6, 2018, the Fifth Circuit vacated the Preliminary Injunction and remanded the case back to the District Court. Construction is ongoing. Rover On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and Pretec Directional Drilling, LLC (“Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. Laney Directional Drilling Co., Atlas Trenchless, LLC, Mears Group, Inc., D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC, and B&T Directional Drilling, Inc. (collectively, with Rover and Pretec, “Defendants”) were added as defendants on April 17, and July 18, 2018. Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Defendants’ motions to dismiss are due on or before September 10, 2018. In January 2018, Ohio EPA sent a letter to the FERC to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24 response to the FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by the FERC and reviewed by the Ohio EPA. In addition, although the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs. Other Litigation and Contingencies We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of June 30, 2018 and December 31, 2017, accruals of approximately $52 million and $53 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period. The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. On April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against Sunoco Pipeline L.P. (“SPLP”) before the Pennsylvania Public Utility Commission (“PUC”). Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2” or “ME2x”) in West Whiteland Township (“the Township”) are unreasonable, unsafe, inadequate, and insufficient for, among other reasons, selecting an improper and unsafe route through densely populated portions of the Township with homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increases the risk of damage to the existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’s Complaint seeks emergency relief by way of an order (i) prohibiting construction of ME2 and ME2x in West Whiteland Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until SPLP fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in which they sit; (iv) requiring SPLP to release to the public its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of operation of ME1 and suspend further construction of ME2 and ME2x in West Whiteland Township. Following a hearing on May 7 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“ALJ”) issued an Order on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to shut down ME1, to discontinue construction of ME2 and ME2x within the Township, and required SPLP to provide various types of information and perform various geotechnical and geophysical studies within the Township. The ALJ’s Order was immediately effective, and SPLP complied by shutting down service on ME1 and discontinuing all construction in the Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the PUC, which issued an Opinion and Order on June 15, 2018 (following a public meeting on June 14, 2018) that reversed in part and affirmed in part the ALJ’s Order. PUC’s Opinion and Order permitted SPLP to resume service on ME1, but continued the shutdown of construction on ME2 and ME2x pending the submission of the following three types of information to PUC: (i) inspection and testing protocols; (ii) comprehensive emergency response plan; and (iii) safety training curriculum for employees and contractors. SPLP submitted the required information on June 22, 2018. On July 2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also required to provide an affidavit that the Pennsylvania Department of Environmental Protection (“DEP”) has issued appropriate approvals for construction of ME2 and ME2x in the Township before recommencing construction of ME2 and ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 2, 2018 the PUC entered an Order lifting the stay of construction on ME2 and ME2x in West Whiteland Township with respect to all areas within the Township where the necessary environmental permits had been issued. Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue the action. Service on ME1 was resumed in accordance with PUC’s Opinion and Order. Senator Dinniman’s Complaint will proceed forward under a schedule to be determined by the ALJ. A prehearing conference with the ALJ is scheduled for August 28, 2018. On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project. On August 1, 2017 the EHB lifted the order as to two drill locations. On August 3, 2017, the EHB lifted the order as to 14 additional locations. The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”). The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting. On August 7, 2017 a final settlement was reached. A stipulated order has been submitted to the EHB Judge with respect to the settlement. The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project. The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation. Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits. Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company. On July 31, 2018 the underlying permit appeals in which the above settlements occurred were withdrawn in a settlement between the appellants and PADEP. That settlement did not involve SPLP. In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project. Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval. SPLP has fulfilled the requirements of those agreements and has been authorized by PADEP to resume drilling the locations. No amounts have been recorded in our June 30, 2018 or December 31, 2017 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Environmental Matters Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position. Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs. In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January 2015. In May 2017, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July 2017, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. Since then, the parties have reached an agreement in principal to resolve all penalties. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality, and we are involved in settlement discussion with the agencies. On January 3, 2018, PADEP issued an Administrative Order to SPLP directing that work on the Mariner East 2 and 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in February 2017, during the construction of the project. SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so SPLP took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, SPLP entered into a Consent Order and Agreement with PADEP that (i) withdraws the Administrative Order; (ii) establishes requirements for compliance with permits on a going forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, SPLP admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that SPLP had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. SPLP concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018. Environmental Remediation Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets. The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. During the three months ended June 30, 2018 and 2017, the Partnership recorded $6 million and $7 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2018 and 2017, the Partnership recorded $11 million and $13 million, respectively, of expenditures related to environmental programs. On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, EPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position. Our pipeline operations are subject to regulation by the United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures. Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Health and Safety Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future. |
Revenue (Notes) |
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Revenue from Contract with Customer [Text Block] | REVENUE The following disclosures discuss the Partnership’s revised revenue recognition policies upon the adoption of ASU 2014-09 on January 1, 2018, as discussed in Note 1. These policies were applied to the current period only, and the amounts reflected in the Partnership’s consolidated financial statements for the three and six months ended June 30, 2017 were recorded under the Partnership’s previous accounting policies. Disaggregation of revenue The Partnership’s consolidated financial statements reflect the following six reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes:
Note 15 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:
Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. NGL and refined products transportation and services revenue Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606. Crude oil transportation and services revenue Our crude oil transportation and service segment are primarily derived from provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606. All other revenue Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard. Contract Balances with Customers The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability. The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services. As of June 30, 2018 and January 1, 2018, no contract assets have been recognized. The Partnership recognizes a contract liability if the customer's payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. As of June 30, 2018, the Partnership had $235 million in deferred revenues representing the current value of our future performance obligations. The amount of revenue recognized for the three and six months ended June 30, 2018 that was included in the deferred revenue liability balance as of January 1, 2018 was $28 million and $63 million, respectively. Performance Obligations At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contacts, only the fixed component of the contracts are included in the table below. As of June 30, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $40.32 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:
Practical Expedients Utilized by the Partnership The Partnership elected the following practical expedients in accordance with Topic 606:
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Derivative Assets And Liabilities |
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Price Risk Management Assets and Liabilities |
Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy. The following table details our outstanding commodity-related derivatives:
Interest Rate Risk We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances. The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income. Derivative Summary The following table provides a summary of our derivative assets and liabilities:
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date. The following tables summarize the amounts recognized in income with respect to our derivative financial instruments:
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Related Party Transactions |
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Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions | RELATED PARTY TRANSACTIONS The Partnership has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. The following table summarizes the affiliate revenues on our consolidated statements of operations:
The following table summarizes the related company balances on our consolidated balance sheets:
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Reportable Segments |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Reportable Segments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reportable Segments | REPORTABLE SEGMENTS Our financial statements currently reflect the following reportable segments, which conduct their business in the United States, as follows: •intrastate transportation and storage; •interstate transportation and storage; •midstream; •NGL and refined products transportation and services; •crude oil transportation and services; and •all other. The amounts included in the NGL and refined products transportation and services segment and the crude oil transportation and services segment have been retrospectively adjusted in these consolidated financial statements as a result of the Sunoco Logistics Merger. Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales, refined product sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our all other segment are primarily reflected in other. We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments. Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership's proportionate ownership. The following tables present financial information by segment:
* As adjusted. See Note 1.
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Guarantor Financial Information (Notes) |
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Guarantor Financial Information [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Condensed Financial Information of Parent Company Only Disclosure [Text Block] | CONSOLIDATING GUARANTOR FINANCIAL INFORMATION Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, is the issuer of multiple series of senior notes that are guaranteed by ETP. These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Partners, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.” The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting. The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows:
* As adjusted. See Note 1.
* As adjusted. See Note 1.
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Operations And Basis of Presentation Accounting Policy (Policies) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basis of Accounting, Policy [Policy Text Block] | Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements of Energy Transfer Partners, L.P. for the year ended December 31, 2017, included in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 23, 2018. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. The historical common units and net income per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity. |
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Accounting Changes [Policy Text Block] | Change in Accounting Policy Inventory Accounting Change During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method. |
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Revenue Recognition, Policy [Policy Text Block] | Revenue Recognition Standard In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018. Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to decreases in revenue (with offsetting decreases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018. The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods. The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales and operating expenses. There were no material changes in the timing of recognition of revenue and therefore no material impacts to the balance sheet upon adoption. The disclosure below shows the impact of adopting the new standard during the period of adoption compared to amounts that would have been reported under the Partnership’s previous revenue recognition policies:
Additional disclosures related to revenue are included in Note 12. Disaggregation of revenue The Partnership’s consolidated financial statements reflect the following six reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes:
Note 15 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:
Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. NGL and refined products transportation and services revenue Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606. Crude oil transportation and services revenue Our crude oil transportation and service segment are primarily derived from provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606. All other revenue Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard. |
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Use of Estimates, Policy [Policy Text Block] | Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates. |
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New Accounting Pronouncements, Policy [Policy Text Block] | Recent Accounting Pronouncements ASU 2016-02 In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840. The Partnership expects to adopt ASU 2016-02 and elect the practical expedient under ASU 2018-01 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. ASU 2017-12 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. ASU 2018-02 In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material. |
Cash And Cash Equivalents Cash and Cash Equivalents (Policies) |
6 Months Ended |
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Jun. 30, 2018 | |
Cash and Cash Equivalents [Abstract] | |
Cash and Cash Equivalents, Unrestricted Cash and Cash Equivalents, Policy [Policy Text Block] | Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. |
Inventories Inventories (Policies) |
6 Months Ended |
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Jun. 30, 2018 | |
Inventory Disclosure [Abstract] | |
Inventory, Policy [Policy Text Block] | We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations. |
Fair Value Measurements Fair Value Measurements (Policies) |
6 Months Ended |
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Jun. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurement, Policy [Policy Text Block] | Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of June 30, 2018 was $33.64 billion and $33.90 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations was $34.28 billion and $33.09 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the six months ended June 30, 2018, no transfers were made between any levels within the fair value hierarchy. |
Revenue (Policies) |
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Revenue [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue Recognition, Policy [Policy Text Block] | Revenue Recognition Standard In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018. Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to decreases in revenue (with offsetting decreases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018. The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods. The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales and operating expenses. There were no material changes in the timing of recognition of revenue and therefore no material impacts to the balance sheet upon adoption. The disclosure below shows the impact of adopting the new standard during the period of adoption compared to amounts that would have been reported under the Partnership’s previous revenue recognition policies:
Additional disclosures related to revenue are included in Note 12. Disaggregation of revenue The Partnership’s consolidated financial statements reflect the following six reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes:
Note 15 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:
Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. NGL and refined products transportation and services revenue Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606. Crude oil transportation and services revenue Our crude oil transportation and service segment are primarily derived from provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606. All other revenue Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard. |
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Revenue Recognition, Deferred Revenue [Policy Text Block] | Contract Balances with Customers The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability. The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services. As of June 30, 2018 and January 1, 2018, no contract assets have been recognized. The Partnership recognizes a contract liability if the customer's payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. As of June 30, 2018, the Partnership had $235 million in deferred revenues representing the current value of our future performance obligations. The amount of revenue recognized for the three and six months ended June 30, 2018 that was included in the deferred revenue liability balance as of January 1, 2018 was $28 million and $63 million, respectively. |
Derivative Assets And Liabilities Derivative Assets and Liabilities (Policies) |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Concentration Risk, Credit Risk, Policy [Policy Text Block] | Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income. |
Derivatives, Policy [Policy Text Block] | Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy. |
Operations And Basis of Presentation Operations and Basis of Presentation (Tables) |
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operations and Basis of Presentation [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block] | As a result of this change in accounting policy, the consolidated statement of operations and comprehensive income in prior periods have been retrospectively adjusted, as follows:
(1) As originally reported amounts reflect certain reclassifications made to conform to the current year presentation. As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows:
The disclosure below shows the impact of adopting the new standard during the period of adoption compared to amounts that would have been reported under the Partnership’s previous revenue recognition policies:
Additional disclosures related to revenue are included in Note 12. |
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Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block] | As of June 30, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $40.32 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:
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Cash And Cash Equivalents (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash and Cash Equivalents [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Cash Provided By Operating Activities | The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:
* As adjusted. See Note 1. |
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Non-Cash Investing And Financing Activities | Non-cash investing and financing activities are as follows:
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Inventories (Tables) |
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Inventory, Gross [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule Of Inventories | Inventories consisted of the following:
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Fair Value Measurements (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Of Assets And Liabilities Measured And Recorded On Recurring Basis | The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 based on inputs used to derive their fair values:
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Net Income Per Limited Partner Unit (Tables) |
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
* As adjusted. See Note 1. For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to preferred unitholders and the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period. |
Equity (Tables) |
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Change In Common Units | The changes in outstanding common units during the six months ended June 30, 2018 were as follows:
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Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions on common units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:
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Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block] | ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods:
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Schedule of Preferred Units [Table Text Block] | Distributions on preferred units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:
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Accumulated Other Comprehensive Income | Accumulated Other Comprehensive Income The following table presents the components of AOCI, net of tax:
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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Rent Expense [Table Text Block] | We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
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Environmental Exit Costs by Cost [Table Text Block] | The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
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Revenue (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block] | As of June 30, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $40.32 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:
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Derivative Assets And Liabilities (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Outstanding Commodity-Related Derivatives | The following table details our outstanding commodity-related derivatives:
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Interest Rate Swaps Outstanding | The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
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Fair Value Of Derivative Instruments | The following table provides a summary of our derivative assets and liabilities:
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Derivatives, Offsetting Fair Value Amounts [Table Text Block] | The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
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Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | The following tables summarize the amounts recognized in income with respect to our derivative financial instruments:
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Related Party Transactions (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions For Period Presented [Table Text Block] | The following table summarizes the affiliate revenues on our consolidated statements of operations:
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Reportable Segments (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sales Revenue, Segment [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | The following tables present financial information by segment:
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Operating Segments [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] |
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Assets Segments [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] |
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Guarantor Financial Information (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Guarantor Financial Information [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Condensed Income Statement [Table Text Block] | The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows:
* As adjusted. See Note 1.
* As adjusted. See Note 1.
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Operations And Basis of Presentation Operations And Organization Narrative (Details) |
1 Months Ended | 3 Months Ended | 6 Months Ended |
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Apr. 30, 2017 |
Dec. 31, 2018 |
Jun. 30, 2018 |
|
SXL and ETP Merger [Member] | |||
Stockholders' Equity Note, Stock Split, Conversion Ratio | 1.5 | ||
FEP [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 50.00% | ||
Citrus [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 50.00% | ||
MEP [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 50.00% | ||
ET Rover Pipeline, LLC [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 50.10% | ||
Rover Pipeline LLC [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 65.00% | ||
Fayetteville Express Pipeline, LLC [Member] | FEP [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||
Citrus [Member] | FGT | |||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||
Subsequent Event [Member] | ETE Merger [Member] | |||
Stockholders' Equity Note, Stock Split, Conversion Ratio | 1.28 |
Operations And Basis of Presentation Schedule of Change in Accounting Policy (Details) - USD ($) $ / shares in Units, $ in Millions |
3 Months Ended | 6 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||||
Cost of products sold | $ 7,140 | $ 4,624 | [1] | $ 13,128 | $ 9,674 | [1] | |||||
OPERATING INCOME | 943 | 736 | [1] | 1,916 | 1,419 | [1] | |||||
Income before income tax expense | 671 | 375 | [1] | 1,510 | 823 | [1] | |||||
Net income | 602 | 296 | [1] | 1,481 | 689 | [1] | |||||
Net income attributable to partners | $ 432 | $ 202 | [1] | $ 1,147 | $ 533 | [1] | |||||
Basic | $ (0.01) | $ (0.04) | [1] | $ 0.23 | $ (0.02) | [1] | |||||
Diluted | $ (0.01) | $ (0.04) | [1] | $ 0.23 | $ (0.02) | [1] | |||||
Comprehensive income | $ 604 | $ 295 | [1] | $ 1,484 | $ 688 | [1] | |||||
Comprehensive income attributable to partners | 434 | 201 | [1] | 1,150 | 532 | [1] | |||||
Inventory, LIFO Reserve, Period Charge | [1] | 0 | |||||||||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | 229 | (387) | [1] | ||||||||
Scenario, Previously Reported [Member] | |||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||||
Cost of products sold | [2] | 4,628 | 9,707 | ||||||||
OPERATING INCOME | 732 | 1,386 | |||||||||
Income before income tax expense | 371 | 790 | |||||||||
Net income | 292 | 656 | |||||||||
Net income attributable to partners | $ 199 | $ 523 | |||||||||
Basic | $ (0.04) | $ (0.04) | |||||||||
Diluted | $ (0.04) | $ (0.04) | |||||||||
Comprehensive income | $ 291 | $ 655 | |||||||||
Comprehensive income attributable to partners | 198 | 522 | |||||||||
Inventory, LIFO Reserve, Period Charge | 56 | ||||||||||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | 410 | ||||||||||
Restatement Adjustment [Member] | |||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||||
Cost of products sold | $ (147) | (4) | $ (333) | (33) | |||||||
OPERATING INCOME | 4 | 33 | |||||||||
Income before income tax expense | 4 | 33 | |||||||||
Net income | 4 | 33 | |||||||||
Net income attributable to partners | $ 3 | $ 10 | |||||||||
Basic | $ 0.00 | $ 0.02 | |||||||||
Diluted | $ 0.00 | $ 0.02 | |||||||||
Comprehensive income | $ 4 | $ 33 | |||||||||
Comprehensive income attributable to partners | $ 3 | 10 | |||||||||
Inventory, LIFO Reserve, Period Charge | (56) | ||||||||||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ (23) | ||||||||||
|
Operations And Basis of Presentation Schedule of Impact of Accounting Standard (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|||||
Natural gas sales | $ 1,024 | $ 1,022 | [1] | $ 2,086 | $ 2,034 | [1] | ||
NGL sales | 2,141 | 1,485 | [1] | 4,171 | 3,032 | [1] | ||
Crude sales | 4,241 | 2,345 | [1] | 7,495 | 4,887 | [1] | ||
Gathering, transportation and other fees | 1,464 | 1,067 | [1] | 2,861 | 2,091 | [1] | ||
Refined product sales | 413 | 304 | [1] | 852 | 775 | [1] | ||
Other | 127 | 353 | [1] | 225 | 652 | [1] | ||
Cost of products sold | 7,140 | 4,624 | [1] | 13,128 | 9,674 | [1] | ||
Operating expenses | 627 | 539 | [1] | 1,231 | 1,031 | [1] | ||
Accounting Standards Update 2014-09 [Member] | ||||||||
Natural gas sales | 1,024 | 2,086 | ||||||
NGL sales | 2,134 | 4,153 | ||||||
Crude sales | 4,238 | 7,488 | ||||||
Gathering, transportation and other fees | 1,611 | 3,194 | ||||||
Refined product sales | 413 | 852 | ||||||
Other | 127 | 225 | ||||||
Cost of products sold | 7,287 | 13,461 | ||||||
Operating expenses | 617 | 1,206 | ||||||
Restatement Adjustment [Member] | ||||||||
Natural gas sales | 0 | 0 | ||||||
NGL sales | 7 | 18 | ||||||
Crude sales | 3 | 7 | ||||||
Gathering, transportation and other fees | (147) | (333) | ||||||
Refined product sales | 0 | 0 | ||||||
Other | 0 | 0 | ||||||
Cost of products sold | (147) | $ (4) | (333) | $ (33) | ||||
Operating expenses | $ 10 | $ 25 | ||||||
|
Acquisitions and Other Transactions Narrative (Details) - USD ($) $ in Millions |
1 Months Ended | 3 Months Ended | 6 Months Ended | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Apr. 30, 2018 |
Feb. 28, 2018 |
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | Dec. 31, 2017 |
||||
Advances to and investments in unconsolidated affiliates | $ 3,636 | $ 3,636 | $ 3,816 | ||||||||
Loss on deconsolidation of CDM | (86) | $ 0 | $ (86) | $ 0 | |||||||
Stock Repurchased During Period, Shares | 1,200,000 | ||||||||||
Cash proceeds from Sunoco LP common unit repurchase | $ 540 | 0 | |||||||||
Gain on Sunoco LP common unit repurchase | 0 | $ 0 | [1] | 172 | $ 0 | ||||||
Sunoco LP | |||||||||||
Stock Repurchased During Period, Shares | 17,286,859 | ||||||||||
Cash proceeds from Sunoco LP common unit repurchase | $ 540 | ||||||||||
USAC Transaction [Member] | |||||||||||
Business Combination, Consideration Transferred | $ 1,700 | ||||||||||
Payments to Acquire Businesses, Gross | $ 1,230 | ||||||||||
USAC Transaction [Member] | USA Compression Partners, LP [Member] | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 19,191,351 | ||||||||||
Class B Units [Member] | USAC Transaction [Member] | USA Compression Partners, LP [Member] | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 6,397,965 | ||||||||||
ETE | USAC Transaction [Member] | USA Compression Partners, LP [Member] | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 12,466,912 | ||||||||||
Equity Issued in Business Combination, Fair Value Disclosure | $ 250 | ||||||||||
USA Compression Partners, LP [Member] | |||||||||||
Advances to and investments in unconsolidated affiliates | 399 | 399 | |||||||||
Accrual for Taxes Other than Income Taxes, Current | $ 45 | $ 45 | |||||||||
|
Advances to and Investments in Affiliates (Details) - USD ($) $ in Millions |
1 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Feb. 28, 2018 |
Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | Apr. 30, 2018 |
Dec. 31, 2017 |
|||
Schedule of Equity Method Investments [Line Items] | ||||||||
Advances to and investments in unconsolidated affiliates | $ 3,636 | $ 3,816 | ||||||
Stock Repurchased During Period, Shares | 1,200,000 | |||||||
Cash proceeds from Sunoco LP common unit repurchase | $ 540 | $ 0 | ||||||
Repurchases of common units | $ 24 | $ 0 | ||||||
RIGS Haynesville Partnership Co. [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity Method Investment, Ownership Percentage | 50.01% | 49.99% | ||||||
Sunoco LP | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity Method Investment, Ownership Percentage | 31.80% | |||||||
Stock Repurchased During Period, Shares | 17,286,859 | |||||||
Cash proceeds from Sunoco LP common unit repurchase | $ 540 | |||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 26,200,000 | |||||||
USAC [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity Method Investment, Ownership Percentage | 26.60% | |||||||
Advances to and investments in unconsolidated affiliates | $ 399 | |||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 19,200,000 | |||||||
USAC [Member] | Class B Units [Member] | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 6,400,000 | |||||||
Sunoco LP | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Advances to and investments in unconsolidated affiliates | $ 535 | |||||||
|
Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions |
6 Months Ended | ||||
---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | |||
Cash and Cash Equivalents [Abstract] | |||||
Accounts receivable | $ 236 | $ 88 | |||
Accounts receivable from related companies | 156 | (115) | |||
Inventories | 299 | 160 | |||
Other current assets | (375) | 77 | |||
Other non-current assets, net | (3) | (39) | |||
Accounts payable | (465) | (286) | |||
Accounts payable to related companies | (99) | 131 | |||
Accrued and other current liabilities | 249 | (389) | |||
Other non-current liabilities | (2) | 7 | |||
Derivative assets and liabilities, net | 233 | (21) | |||
Net change in operating assets and liabilities, net of effects of acquisitions | $ 229 | $ (387) | |||
|
Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) - USD ($) $ in Millions |
6 Months Ended | |
---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
|
NON-CASH INVESTING ACTIVITIES: | ||
Accrued capital expenditures | $ 1,007 | $ 1,363 |
USAC limited partner interests received in the CDM Contribution (see Note 2) | 411 | 0 |
NON-CASH FINANCING ACTIVITIES: | ||
Contribution of property, plant and equipment from noncontrolling interest | $ 0 | $ 988 |
Inventories (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Inventory, Gross [Abstract] | ||
Natural gas, NGLs and refined products | $ 434 | $ 733 |
Crude oil | 571 | 551 |
Spare parts and other | 251 | 305 |
Total inventories | $ 1,256 | $ 1,589 |
Fair Value Measurements Narrative (Details) - USD ($) $ in Millions |
6 Months Ended | |
---|---|---|
Jun. 30, 2018 |
Dec. 31, 2017 |
|
Fair Value Measurements [Abstract] | ||
Transfers between levels in fair value hierarchy | $ 0 | |
Aggregate fair value of long-term debt | 33,640 | $ 34,280 |
Long-term Debt | $ 33,900 | $ 33,090 |
Fair Value Measurements Fair Value Heigharchy (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Derivative Liability, Fair Value, Gross Liability | $ (923) | $ (557) |
Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 413 | 320 |
Other Assets, Fair Value Disclosure | 21 | 21 |
Assets, Fair Value Disclosure, Recurring | 434 | 341 |
Interest rate derivatives, Liabilities | (147) | (219) |
Price Risk Derivative Liabilities, at Fair Value | (776) | (338) |
Liabilities, Fair Value Disclosure, Recurring | (923) | (557) |
Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 334 | 276 |
Other Assets, Fair Value Disclosure | 14 | 14 |
Assets, Fair Value Disclosure, Recurring | 348 | 290 |
Interest rate derivatives, Liabilities | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | (713) | (300) |
Liabilities, Fair Value Disclosure, Recurring | (713) | (300) |
Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 79 | 44 |
Other Assets, Fair Value Disclosure | 7 | 7 |
Assets, Fair Value Disclosure, Recurring | 86 | 51 |
Interest rate derivatives, Liabilities | (147) | (219) |
Price Risk Derivative Liabilities, at Fair Value | (63) | (38) |
Liabilities, Fair Value Disclosure, Recurring | (210) | (257) |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 22 | 11 |
Price Risk Derivative Liabilities, at Fair Value | (70) | (24) |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 22 | 11 |
Price Risk Derivative Liabilities, at Fair Value | (70) | (24) |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | 13 |
Price Risk Derivative Liabilities, at Fair Value | (2) | (15) |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | (1) | (1) |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 1 | 13 |
Price Risk Derivative Liabilities, at Fair Value | (1) | (14) |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 11 | 70 |
Price Risk Derivative Liabilities, at Fair Value | (14) | (57) |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 11 | 70 |
Price Risk Derivative Liabilities, at Fair Value | (14) | (57) |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 9 | 8 |
Price Risk Derivative Liabilities, at Fair Value | (5) | |
Trading Liabilities, Fair Value Disclosure | 2 | |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Trading Liabilities, Fair Value Disclosure | 0 | |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 9 | 8 |
Price Risk Derivative Liabilities, at Fair Value | (5) | |
Trading Liabilities, Fair Value Disclosure | 2 | |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 69 | 23 |
Price Risk Derivative Liabilities, at Fair Value | (57) | (22) |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 69 | 23 |
Price Risk Derivative Liabilities, at Fair Value | (57) | (22) |
Commodity Derivatives - Power [Member] | Put Option [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Commodity Derivatives - Power [Member] | Put Option [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Commodity Derivatives - Power [Member] | Put Option [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 300 | 191 |
Price Risk Derivative Liabilities, at Fair Value | (316) | (186) |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 300 | 191 |
Price Risk Derivative Liabilities, at Fair Value | (316) | (186) |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | (5) | (25) |
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Liabilities, at Fair Value | (5) | (25) |
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Price Risk Derivative Liabilities, at Fair Value | (307) | (1) |
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Price Risk Derivative Liabilities, at Fair Value | (307) | (1) |
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | $ 0 | 0 |
Commodity Derivatives - Crude [Member] | Forwards Swaps [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Price Risk Derivative Liabilities, at Fair Value | (6) | |
Commodity Derivatives - Crude [Member] | Forwards Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Price Risk Derivative Liabilities, at Fair Value | (6) | |
Commodity Derivatives - Crude [Member] | Forwards Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | $ 0 |
Net Income Per Limited Partner Unit Reconciliation of Basic and Diluted EPU (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions |
3 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | |||
Earnings Per Share [Abstract] | ||||||||
NET INCOME | $ 602 | $ 296 | $ 1,481 | $ 689 | ||||
Less: Net income attributable to noncontrolling interest | 170 | 94 | 334 | 156 | ||||
Net income attributable to partners | 432 | 202 | 1,147 | 533 | ||||
Series A Preferred Units Interest in Net Income | 15 | 0 | 30 | 0 | ||||
Series B Preferred Units Interest in Net Income | 9 | 0 | 18 | 0 | ||||
Series C Preferred Units Interest in Net Income | 6 | 0 | 6 | 0 | ||||
General Partner’s interest in net income | 402 | 251 | 804 | 457 | ||||
Class H Unitholder’s interest in net income | 0 | 0 | 0 | 93 | ||||
Common Unitholders’ interest in net income (loss) | 0 | (49) | 289 | (17) | ||||
Additional (earnings) distributions allocated to General Partner | (1) | 15 | (3) | 12 | ||||
Distributions on employee unit awards, net of allocation to General Partner | (7) | (6) | (15) | (13) | ||||
Net Income (Loss) from Continuing Operations Available to Common Shareholders, Basic | $ (8) | $ (40) | $ 271 | $ (18) | ||||
Weighted average Common Units – basic | 1,165.4 | 1,021.7 | 1,164.6 | 922.5 | ||||
Weighted average Common Units – diluted | 1,165.4 | 1,021.7 | 1,169.4 | 922.5 | ||||
Basic | $ (0.01) | $ (0.04) | $ 0.23 | $ (0.02) | ||||
Diluted | $ (0.01) | $ (0.04) | $ 0.23 | $ (0.02) | ||||
|
Net Income Per Limited Partner Unit Narrative (Details) |
1 Months Ended |
---|---|
Apr. 30, 2017 | |
SXL and ETP Merger [Member] | |
Stockholders' Equity Note, Stock Split, Conversion Ratio | 1.5 |
Debt Obligations Narrative (Details) $ in Millions |
6 Months Ended |
---|---|
Jun. 30, 2018
USD ($)
| |
Early Repayment of Senior Debt | $ 1,650 |
Proceeds from Issuance of Senior Long-term Debt | 2,960 |
Bakken Pipeline [Member] | Bakken Term Note [Member] | |
Line of Credit Facility, Maximum Borrowing Capacity | 2,500 |
4.20% Senior Notes due 2023 [Member] | ETP [Member] | |
Senior Notes | $ 500 |
Debt Instrument, Interest Rate, Stated Percentage | 4.20% |
4.95% Senior Notes due 2028 [Member] | ETP [Member] | |
Senior Notes | $ 1,000 |
Debt Instrument, Interest Rate, Stated Percentage | 4.95% |
5.80% Senior Notes due 2038 [Member] | ETP [Member] | |
Senior Notes | $ 500 |
Debt Instrument, Interest Rate, Stated Percentage | 5.80% |
6.0% Senior Notes due 2048 [Member] | ETP [Member] | |
Senior Notes | $ 1,000 |
Debt Instrument, Interest Rate, Stated Percentage | 6.00% |
2.50% Senior Notes due June 2018 [Member] | ETP [Member] | |
Senior Notes | $ 650 |
Debt Instrument, Interest Rate, Stated Percentage | 2.50% |
7.00% Senior Notes, due June 15, 2018 [Member] | Panhandle [Member] | |
Senior Notes | $ 400 |
Debt Instrument, Interest Rate, Stated Percentage | 7.00% |
6.7% Senior Notes, due July 1, 2018 [Member] | ETP [Member] | |
Senior Notes | $ 600 |
Debt Instrument, Interest Rate, Stated Percentage | 6.70% |
ETP Credit Facility due December 2022 [Member] | ETP [Member] | |
Line of Credit Facility, Current Borrowing Capacity | $ 2,610 |
Long-term Line of Credit | 1,230 |
Long-term Commercial Paper, Noncurrent | 1,230 |
Line of Credit Facility, Maximum Borrowing Capacity | 4,000 |
Letters of Credit Outstanding, Amount | $ 167 |
Line of Credit Facility, Interest Rate at Period End | 2.87% |
ETP Credit Facility due December 2022 [Member] | ETP [Member] | Accordion feature [Member] | |
Long-term Line of Credit | $ 6,000 |
ETP $1.0 billion 364-day Credit Facility due December 2018 [Member] | ETP [Member] | |
Long-term Line of Credit | 0 |
Line of Credit Facility, Maximum Borrowing Capacity | 1,000 |
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member] | |
Long-term Line of Credit | $ 2,500 |
Line of Credit Facility, Interest Rate at Period End | 3.72% |
Equity Narrative (Details) - USD ($) $ / shares in Units, $ in Millions |
1 Months Ended | 3 Months Ended | 6 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Jul. 31, 2018 |
Apr. 30, 2018 |
Jun. 30, 2018 |
Mar. 31, 2018 |
Dec. 31, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | |||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI for Sale of Securities, before Tax | $ 2 | |||||||||
Proceeds from Issuance of Preferred Limited Partners Units | 436 | $ 0 | ||||||||
Proceeds from Issuance of Common Limited Partners Units | 39 | $ 990 | ||||||||
ETP [Member] | ||||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | 0 | |||||||||
Equity Distribution Agreements, Value of Units Available to be Issued | $ 752 | 752 | ||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units | 1,000 | |||||||||
Rate | $ 0.5650 | $ 0.5650 | $ 0.5650 | |||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 39 | |||||||||
Series A Preferred Units [Member] | ||||||||||
Rate | $ 31.250 | 15.451 | ||||||||
Preferred Stock, Shares Issued | 950,000 | 950,000 | ||||||||
Series B Preferred Units [Member] | ||||||||||
Rate | $ 33.125 | $ 16.378 | ||||||||
Preferred Stock, Shares Issued | 550,000 | 550,000 | ||||||||
Series C Preferred Units [Member] | ||||||||||
Rate | $ 0.56337 | |||||||||
Preferred Units, Issued | 18,000,000 | |||||||||
Preferred Stock, Dividend Rate, Percentage | 7.375% | |||||||||
Shares Issued, Price Per Share | $ 25 | |||||||||
Preferred Units, Liquidation Spread, Percent | 4.53% | |||||||||
Proceeds from Issuance of Preferred Limited Partners Units | $ 450 | |||||||||
Series D Preferred Units [Member] | Subsequent Event [Member] | ||||||||||
Preferred Units, Issued | 17,800,000 | |||||||||
Preferred Stock, Dividend Rate, Percentage | 7.625% | |||||||||
Shares Issued, Price Per Share | $ 25 | |||||||||
Preferred Units, Liquidation Spread, Percent | 4.378% | |||||||||
Proceeds from Issuance of Preferred Limited Partners Units | $ 445 | |||||||||
|
Equity Common Unit Activity (Details) shares in Millions |
6 Months Ended |
---|---|
Jun. 30, 2018
shares
| |
Partners' Capital Notes [Abstract] | |
Number of common units at December 31, 2017 | 1,164.1 |
Common units issued in connection with the distribution reinvestment plan | 2.1 |
Common units issued in connection with certain transactions | 1.3 |
Issuance of common units under equity incentive plans | 0.1 |
Repurchases of common units in open-market transactions | (1.2) |
Number of common units at June 30, 2018 | 1,166.4 |
Equity Quarterly Distributions Of Available Cash (Details) - $ / shares |
3 Months Ended | ||
---|---|---|---|
Jun. 30, 2018 |
Mar. 31, 2018 |
Dec. 31, 2017 |
|
ETP [Member] | |||
Distribution Made to Member or Limited Partner [Line Items] | |||
Record Date | Aug. 06, 2018 | May 07, 2018 | Feb. 08, 2018 |
Payment Date | Aug. 14, 2018 | May 15, 2018 | Feb. 14, 2018 |
Rate | $ 0.5650 | $ 0.5650 | $ 0.5650 |
Preferred Units [Member] | |||
Distribution Made to Member or Limited Partner [Line Items] | |||
Record Date | Aug. 01, 2018 | Feb. 01, 2018 | |
Payment Date | Aug. 15, 2018 | Feb. 15, 2018 | |
Series A Preferred Units [Member] | |||
Distribution Made to Member or Limited Partner [Line Items] | |||
Rate | $ 31.250 | $ 15.451 | |
Series B Preferred Units [Member] | |||
Distribution Made to Member or Limited Partner [Line Items] | |||
Rate | 33.125 | $ 16.378 | |
Series C Preferred Units [Member] | |||
Distribution Made to Member or Limited Partner [Line Items] | |||
Rate | $ 0.56337 |
Equity Net IDR Schedule (Details) - USD ($) $ in Millions |
6 Months Ended | 12 Months Ended | |
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2020 |
Dec. 31, 2019 |
|
ETE | Subsequent Event [Member] | |||
Relinquishment of Incentive Distributions | $ 69 | $ 33 | $ 128 |
Equity AOCI (Details) - USD ($) $ in Millions |
6 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Dec. 31, 2017 |
|||
Partners' Capital Notes [Abstract] | ||||
Available-for-sale securities (1) | [1] | $ 4 | $ 8 | |
Foreign currency translation adjustment | (5) | (5) | ||
Actuarial loss related to pensions and other postretirement benefits | (7) | (5) | ||
Investments in unconsolidated affiliates, net | 12 | 5 | ||
Total AOCI, net of tax | $ 4 | $ 3 | ||
|
Income Taxes (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended |
---|---|---|
Jun. 30, 2018 |
Jun. 30, 2018 |
|
Income Tax Disclosure [Abstract] | ||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount | $ 3 | $ 70 |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details) |
1 Months Ended | 3 Months Ended | 6 Months Ended | ||||
---|---|---|---|---|---|---|---|
Feb. 28, 2018
USD ($)
|
Jun. 30, 2018
USD ($)
|
Jun. 30, 2017
USD ($)
|
Jun. 30, 2018
USD ($)
|
Jun. 30, 2017
USD ($)
|
Jan. 31, 2018
USD ($)
|
Dec. 31, 2017
USD ($)
|
|
Maximum lease expiration year | Dec. 31, 2034 | ||||||
Loss contingency accrual, at carrying value | $ 52,000,000 | $ 52,000,000 | $ 53,000,000 | ||||
Amounts recorded in balance sheets for contingencies and current litigation not disclosed | 0 | 0 | |||||
Accrual for Environmental Loss Contingencies | 318,000,000 | 318,000,000 | $ 350,000,000 | ||||
Civil penalties | $ 12,600,000 | ||||||
Compensatory Damages [Member] | |||||||
Gain Contingency, Unrecorded Amount | 319,000,000 | 319,000,000 | |||||
Disgorgement [Member] | |||||||
Gain Contingency, Unrecorded Amount | 595,000,000 | 595,000,000 | |||||
Expense Reimbursement [Member] | |||||||
Gain Contingency, Unrecorded Amount | 1,000,000 | 1,000,000 | |||||
Final Judgement [Member] | |||||||
Gain Contingency, Unrecorded Amount | 536,000,000 | 536,000,000 | |||||
Sunoco LP | Term loan due 2019 [Member] | |||||||
Senior Notes | $ 2,035,000,000 | $ 2,035,000,000 | |||||
Sunoco, Inc. [Member] | |||||||
Loss Contingency, Pending Claims, Number | 6 | 6 | |||||
Payments for Environmental Liabilities | $ 6,000,000 | $ 7,000,000 | $ 11,000,000 | $ 13,000,000 | |||
Proposed Environmental Penalty | $ 200,000 | $ 200,000 | |||||
Sunoco [Member] | |||||||
Sites where remediation operations are responsibility of third parties | 41 | 41 | |||||
Rover Pipeline LLC [Member] | |||||||
Proposed Environmental Penalty | $ 2,600,000 | $ 2,600,000 | |||||
4.875% senior notes due 2023 [Member] | Sunoco LP | |||||||
Senior Notes | $ 1,000,000,000 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.875% | ||||||
5.500% senior notes due 2026 [Member] | Sunoco LP | |||||||
Senior Notes | $ 800,000,000 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | ||||||
5.875% senior notes due 2028 [Member] | Sunoco LP | |||||||
Senior Notes | $ 400,000,000 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.875% |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Operating Leases, Rental Expense (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Rental expense | $ 22 | $ 19 | $ 39 | $ 39 |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Environmental Exit Cost [Line Items] | ||
Current | $ 42 | $ 36 |
Non-current | 276 | 314 |
Total environmental liabilities | $ 318 | $ 350 |
Revenue (Details) $ in Millions |
3 Months Ended | 6 Months Ended |
---|---|---|
Jun. 30, 2018
USD ($)
|
Jun. 30, 2018
USD ($)
|
|
Contract with Customer, Asset, Gross | $ 0 | $ 0 |
Deferred Revenue | 235 | 235 |
Contract with Customer, Liability, Revenue Recognized | 28 | 63 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-12-31 | ||
Revenue, Remaining Performance Obligation | 2,598 | 2,598 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-12-31 | ||
Revenue, Remaining Performance Obligation | 5,048 | 5,048 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-12-31 | ||
Revenue, Remaining Performance Obligation | 4,604 | 4,604 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-12-31 | ||
Revenue, Remaining Performance Obligation | 28,071 | 28,071 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | ||
Revenue, Remaining Performance Obligation | $ 40,321 | $ 40,321 |
Derivative Assets And Liabilities Outstanding Commodity Derivatives (Details) |
6 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018
MMbtu
barrels
bbl
Megawatt
|
Dec. 31, 2017
MMbtu
barrels
bbl
Megawatt
|
|||
Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | Natural Gas [Member] | ||||
Notional Volume | (4,700) | |||
Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | Natural Gas [Member] | ||||
Notional Volume | (5,360) | |||
Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member] | Natural Gas [Member] | ||||
Notional Volume | (21,475) | (39,770) | ||
Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | Natural Gas [Member] | ||||
Notional Volume | (465) | (1,078) | ||
Fixed Swaps/Futures [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Fixed Swaps/Futures [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Fixed Swaps/Futures [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2019 | 2019 | ||
Fixed Swaps/Futures [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | ||||
Term Of Commodity Derivatives | 2019 | 2019 | ||
Forward Physical Swaps [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Forward Physical Swaps [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2020 | 2020 | ||
Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | Natural Gas [Member] | ||||
Notional Volume | (174,465) | (145,105) | ||
Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | Natural Gas Liquids [Member] | ||||
Notional Volume | bbl | (1,590) | (2,493) | ||
Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | Crude Oil [Member] | ||||
Notional Volume | bbl | (44,190) | |||
Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | Power [Member] | ||||
Notional Volume | Megawatt | (3,196,100) | (435,960) | ||
Forwards Swaps [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Forwards Swaps [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | ||||
Term Of Commodity Derivatives | 2019 | 2019 | ||
Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Long [Member] | Natural Gas [Member] | ||||
Notional Volume | (21,475) | (39,770) | ||
Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | Natural Gas [Member] | ||||
Notional Volume | (6,600) | (4,650) | ||
Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member] | Natural Gas [Member] | ||||
Notional Volume | (21,475) | (39,770) | ||
Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | Natural Gas [Member] | ||||
Notional Volume | [1] | (102,328) | (48,510) | |
Basis Swaps IFERC/NYMEX [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Basis Swaps IFERC/NYMEX [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Basis Swaps IFERC/NYMEX [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2020 | 2020 | ||
Basis Swaps IFERC/NYMEX [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2020 | 2020 | ||
Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | Power [Member] | ||||
Notional Volume | Megawatt | (996,172) | (137,600) | ||
Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | Natural Gas [Member] | ||||
Notional Volume | (52,413) | (87,253) | ||
Swing Swaps IFERC [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Swing Swaps IFERC [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2019 | 2019 | ||
Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | Refined Products [Member] | ||||
Notional Volume | barrels | (1,076) | (3,783) | ||
Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | Power [Member] | ||||
Notional Volume | Megawatt | (42,768) | (25,760) | ||
Forward Swaps [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Forward Swaps [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Crude Oil [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Forward Swaps [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | ||||
Term Of Commodity Derivatives | 2019 | 2019 | ||
Forward Swaps [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Crude Oil [Member] | ||||
Term Of Commodity Derivatives | 2019 | 2019 | ||
Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | ||||
Term Of Commodity Derivatives | 2018 | |||
Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | ||||
Term Of Commodity Derivatives | 2018 | 2018 | ||
Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | Natural Gas [Member] | ||||
Notional Volume | (3,043) | |||
Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | Power [Member] | ||||
Notional Volume | Megawatt | (30,532) | (153,600) | ||
Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | Natural Gas [Member] | ||||
Notional Volume | (13,000) | |||
Put Option [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | ||||
Term Of Commodity Derivatives | 2018 | |||
|
Derivative Assets And Liabilities Outstanding Interest Rate Derivatives (Details) - USD ($) $ in Millions |
6 Months Ended | ||||||
---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Dec. 31, 2017 |
||||||
July 2018 [Member] | |||||||
Notional Amount | [1] | $ 0 | $ 300 | ||||
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | |||||
December 2018 [Member] | |||||||
Notional Amount | $ 1,200 | 1,200 | |||||
Type | [2] | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | |||||
July 2019 [Member] | |||||||
Notional Amount | [1] | $ 400 | 300 | ||||
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.56% and receive a floating rate | |||||
July 2020 [Member] | |||||||
Notional Amount | [1] | $ 400 | 400 | ||||
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | |||||
July 2021 [Member] | |||||||
Notional Amount | [1] | $ 400 | 0 | ||||
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.55% and receive a floating rate | |||||
March 2019 [Member] | |||||||
Notional Amount | $ 300 | $ 300 | |||||
Type | [2] | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | |||||
|
Derivative Assets And Liabilities Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Total derivatives assets | $ 413 | $ 320 |
Total derivatives liabilities | (923) | (557) |
Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) | ||
Total derivatives assets | 0 | 14 |
Total derivatives liabilities | (2) | (2) |
Not Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 413 | 306 |
Total derivatives liabilities | (921) | (555) |
Not Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) | ||
Total derivatives assets | 307 | 262 |
Total derivatives liabilities | (352) | (281) |
Not Designated as Hedging Instrument [Member] | Commodity derivatives | ||
Total derivatives assets | 106 | 44 |
Total derivatives liabilities | (422) | (55) |
Not Designated as Hedging Instrument [Member] | Interest rate derivatives | ||
Total derivatives assets | 0 | 0 |
Total derivatives liabilities | $ (147) | $ (219) |
Derivative Assets And Liabilities Fair Value of Derivatives, Netting Basis (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 413 | $ 320 |
Derivative Liability, Fair Value, Gross Liability | (923) | (557) |
Derivative Asset, Fair Value, Amount Offset Against Collateral | (49) | (20) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 49 | 20 |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (306) | (263) |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 306 | 263 |
Derivative Asset, Fair Value, Net | 58 | 37 |
Derivative Liability, Fair Value, Net | (568) | (274) |
Without offsetting agreements [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | (147) | (219) |
OTC Contracts [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 106 | 44 |
Derivative Liability, Fair Value, Gross Liability | (422) | (55) |
Broker cleared derivative contracts [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 307 | 276 |
Derivative Liability, Fair Value, Gross Liability | $ (354) | $ (283) |
Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Recognized OCI On Derivatives (Effective Portion) (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Commodity Derivatives [Member] | ||||
Commodity derivatives | $ 6 | $ 6 | $ 9 | $ 2 |
Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Amount Of Gain/(Loss) Reclassified From AOCI Into Income (Effective Portion) (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|||||
Amount of Gain/(Loss) Recognized in Income on Derivatives | $ (264) | $ (3) | $ (268) | $ 4 | ||||
Gains (losses) on interest rate derivatives | 20 | (25) | [1] | 72 | (20) | [1] | ||
Commodity Derivatives - Trading [Member] | ||||||||
Amount of Gain/(Loss) Recognized in Income on Derivatives | 16 | 15 | 33 | 26 | ||||
Commodity derivatives | ||||||||
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | 6 | 6 | 9 | 2 | ||||
Amount of Gain/(Loss) Recognized in Income on Derivatives | (300) | 7 | (373) | (3) | ||||
Other Income (Expenses) [Member] | Embedded Derivatives in Preferred Units [Member] | ||||||||
Amount of Gain/(Loss) Recognized in Income on Derivatives | $ 0 | $ 0 | $ 0 | $ 1 | ||||
|
Related Party Transactions Affiliated Revenue (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Related Party Transactions [Abstract] | ||||
Affiliated revenues | $ 222 | $ 133 | $ 508 | $ 251 |
Related Party Transactions Related Party A/R and A/P (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Total accounts receivable from related companies: | $ 334 | $ 318 |
Total accounts payable to related companies: | 329 | 209 |
USAC [Member] | ||
Total accounts payable to related companies: | 45 | 0 |
Sunoco LP | ||
Notes Receivable, Related Parties, Noncurrent | 85 | 85 |
Total accounts receivable from related companies: | 184 | 219 |
Total accounts payable to related companies: | 195 | 195 |
FGT | ||
Total accounts receivable from related companies: | 18 | 11 |
Other | ||
Total accounts receivable from related companies: | 132 | 88 |
Total accounts payable to related companies: | $ 89 | $ 14 |
Reportable Segments Segment Revenues (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | $ 9,410 | $ 6,576 | [1] | $ 17,690 | $ 13,471 | [1] | ||
Intrastate transportation and storage | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 813 | 753 | 1,688 | 1,569 | ||||
Intrastate transportation and storage | Revenues from external customers | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 761 | 699 | 1,578 | 1,467 | ||||
Intrastate transportation and storage | Intersegment revenues | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 52 | 54 | 110 | 102 | ||||
Interstate transportation and storage | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 328 | 207 | 644 | 442 | ||||
Interstate transportation and storage | Revenues from external customers | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 323 | 201 | 636 | 432 | ||||
Interstate transportation and storage | Intersegment revenues | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 5 | 6 | 8 | 10 | ||||
Midstream | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 1,874 | 1,615 | 3,488 | 3,252 | ||||
Midstream | Revenues from external customers | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 594 | 633 | 1,034 | 1,198 | ||||
Midstream | Intersegment revenues | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 1,280 | 982 | 2,454 | 2,054 | ||||
NGL and refined products transportation and services | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 2,568 | 1,779 | 5,114 | 4,045 | ||||
NGL and refined products transportation and services | Revenues from external customers | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 2,472 | 1,767 | 4,930 | 3,885 | ||||
NGL and refined products transportation and services | Intersegment revenues | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 96 | 12 | 184 | 160 | ||||
Crude oil transportation and services | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 4,803 | 2,465 | 8,548 | 5,040 | ||||
Crude oil transportation and services | Revenues from external customers | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 4,789 | 2,460 | 8,520 | 5,035 | ||||
Crude oil transportation and services | Intersegment revenues | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 14 | 5 | 28 | 5 | ||||
All other | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 502 | 870 | 1,073 | 1,640 | ||||
All other | Revenues from external customers | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 471 | 816 | 992 | 1,454 | ||||
All other | Intersegment revenues | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | 31 | 54 | 81 | 186 | ||||
Eliminations | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Revenues | $ (1,478) | $ (1,113) | $ (2,865) | $ (2,517) | ||||
|
Reportable Segments Segment Adjusted EBITDA (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | ||||
Segment Reporting Information [Line Items] | ||||||||
Segment Adjusted EBITDA | $ 2,051 | $ 1,545 | $ 3,932 | $ 2,990 | ||||
Depreciation, depletion and amortization | (588) | (557) | (1,191) | (1,117) | ||||
Interest expense, net | (358) | (336) | [1] | (704) | (668) | |||
Gain on Sunoco LP common unit repurchase | 0 | 0 | [1] | 172 | 0 | |||
Loss on deconsolidation of CDM | (86) | 0 | (86) | 0 | ||||
Gains (losses) on interest rate derivatives | 20 | (25) | [1] | 72 | (20) | |||
Non-cash compensation expense | (21) | (15) | (41) | (38) | ||||
Unrealized gains (losses) on commodity risk management activities | (265) | 34 | (352) | 98 | ||||
Adjusted EBITDA related to unconsolidated affiliates | (228) | (247) | 413 | 486 | ||||
Equity in earnings (losses) of unconsolidated affiliates | 106 | (61) | [1] | 34 | 12 | |||
Other, net | 40 | 37 | 87 | 52 | ||||
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | 671 | 375 | [1] | 1,510 | 823 | |||
Intrastate transportation and storage | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Segment Adjusted EBITDA | 208 | 148 | 400 | 317 | ||||
Interstate transportation and storage | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Segment Adjusted EBITDA | 330 | 262 | 653 | 527 | ||||
Midstream | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Segment Adjusted EBITDA | 414 | 412 | 791 | 732 | ||||
NGL and refined products transportation and services | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Segment Adjusted EBITDA | 461 | 388 | 912 | 769 | ||||
Crude oil transportation and services | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Segment Adjusted EBITDA | 548 | 228 | 1,012 | 415 | ||||
All other | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Segment Adjusted EBITDA | $ 90 | $ 107 | $ 164 | $ 230 | ||||
|
Reportable Segments Segment Assets (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Segment Reporting Information [Line Items] | ||
Assets | $ 78,570 | $ 77,965 |
Intrastate transportation and storage | ||
Segment Reporting Information [Line Items] | ||
Assets | 5,604 | 5,020 |
Interstate transportation and storage | ||
Segment Reporting Information [Line Items] | ||
Assets | 14,037 | 13,518 |
Midstream | ||
Segment Reporting Information [Line Items] | ||
Assets | 19,949 | 20,004 |
NGL and refined products transportation and services | ||
Segment Reporting Information [Line Items] | ||
Assets | 17,517 | 17,600 |
Crude oil transportation and services | ||
Segment Reporting Information [Line Items] | ||
Assets | 18,168 | 17,736 |
All other | ||
Segment Reporting Information [Line Items] | ||
Assets | $ 3,295 | $ 4,087 |
Guarantor Financial Information Balance Sheet (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
Jun. 30, 2017 |
Dec. 31, 2016 |
||||
---|---|---|---|---|---|---|---|---|
Cash and Cash Equivalents, at Carrying Value | $ 494 | $ 306 | $ 272 | [1] | $ 360 | [1] | ||
Other current assets | 6,053 | 6,222 | ||||||
Property, Plant and Equipment, Net | 59,776 | 58,437 | ||||||
Advances to and investments in unconsolidated affiliates | 3,636 | 3,816 | ||||||
Other Assets, Noncurrent | 8,611 | 9,184 | ||||||
Assets | 78,570 | 77,965 | ||||||
Liabilities, Current | 6,641 | 6,994 | ||||||
Liabilities, Noncurrent | 37,893 | 36,820 | ||||||
Noncontrolling interest | 6,171 | 5,882 | ||||||
Other non-current liabilities | 1,079 | 1,084 | ||||||
Partners' Capital | 27,865 | 28,269 | ||||||
Liabilities and Equity | 78,570 | 77,965 | ||||||
Parent Guarantor [Member] | ||||||||
Cash and Cash Equivalents, at Carrying Value | 0 | 0 | 0 | 0 | ||||
Other current assets | 0 | 0 | ||||||
Property, Plant and Equipment, Net | 0 | 0 | ||||||
Advances to and investments in unconsolidated affiliates | 51,199 | 48,378 | ||||||
Other Assets, Noncurrent | 8 | 0 | ||||||
Assets | 51,207 | 48,378 | ||||||
Liabilities, Current | 390 | (1,496) | ||||||
Liabilities, Noncurrent | 22,949 | 21,604 | ||||||
Noncontrolling interest | 0 | 0 | ||||||
Partners' Capital | 27,868 | 28,270 | ||||||
Liabilities and Equity | 51,207 | 48,378 | ||||||
Subsidiary Issuer [Member] | ||||||||
Cash and Cash Equivalents, at Carrying Value | 0 | (3) | 23 | 41 | ||||
Other current assets | 57 | 159 | ||||||
Property, Plant and Equipment, Net | 0 | 0 | ||||||
Advances to and investments in unconsolidated affiliates | 12,078 | 11,648 | ||||||
Other Assets, Noncurrent | 0 | 0 | ||||||
Assets | 12,135 | 11,804 | ||||||
Liabilities, Current | (3,571) | (3,660) | ||||||
Liabilities, Noncurrent | 7,606 | 7,607 | ||||||
Noncontrolling interest | 0 | 0 | ||||||
Partners' Capital | 8,100 | 7,857 | ||||||
Liabilities and Equity | 12,135 | 11,804 | ||||||
Non-Guarantor Subsidiaries [Member] | ||||||||
Cash and Cash Equivalents, at Carrying Value | 494 | 309 | 249 | 319 | ||||
Other current assets | 8,527 | 6,063 | ||||||
Property, Plant and Equipment, Net | 59,776 | 58,437 | ||||||
Advances to and investments in unconsolidated affiliates | 3,636 | 3,816 | ||||||
Other Assets, Noncurrent | 8,603 | 9,184 | ||||||
Assets | 81,036 | 77,809 | ||||||
Liabilities, Current | 12,353 | 12,150 | ||||||
Liabilities, Noncurrent | 7,338 | 7,609 | ||||||
Noncontrolling interest | 6,171 | 5,882 | ||||||
Partners' Capital | 55,174 | 52,168 | ||||||
Liabilities and Equity | 81,036 | 77,809 | ||||||
Adjustments And Eliminations [Member] | ||||||||
Cash and Cash Equivalents, at Carrying Value | 0 | 0 | $ 0 | $ 0 | ||||
Other current assets | (2,531) | 0 | ||||||
Property, Plant and Equipment, Net | 0 | 0 | ||||||
Advances to and investments in unconsolidated affiliates | (63,277) | (60,026) | ||||||
Other Assets, Noncurrent | 0 | 0 | ||||||
Assets | (65,808) | (60,026) | ||||||
Liabilities, Current | (2,531) | 0 | ||||||
Liabilities, Noncurrent | 0 | 0 | ||||||
Noncontrolling interest | 0 | 0 | ||||||
Partners' Capital | (63,277) | (60,026) | ||||||
Liabilities and Equity | $ (65,808) | $ (60,026) | ||||||
|
Guarantor Financial Information Statements of Operations (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
[1] | ||||
Revenues | $ 9,410 | $ 6,576 | [1] | $ 17,690 | $ 13,471 | |||
Costs and Expenses | 8,467 | 5,840 | [1] | 15,774 | 12,052 | |||
OPERATING INCOME | 943 | 736 | [1] | 1,916 | 1,419 | |||
Interest Expense | (358) | (336) | [1] | (704) | (668) | |||
Equity in earnings (losses) of unconsolidated affiliates | 106 | (61) | [1] | 34 | 12 | |||
Gains (losses) on interest rate derivatives | 20 | (25) | [1] | 72 | (20) | |||
Deconsolidation, Gain (Loss), Amount | (86) | 0 | (86) | 0 | ||||
Gain on Sunoco LP common unit repurchase | 0 | 0 | [1] | 172 | 0 | |||
Other Nonoperating Income (Expense) | 46 | 61 | [1] | 106 | 80 | |||
Income (Loss) Attributable to Parent, before Tax | 671 | 375 | [1] | 1,510 | 823 | |||
Income tax expense | 69 | 79 | [1] | 29 | 134 | |||
Net income | 602 | 296 | [1] | 1,481 | 689 | |||
Less: Net income attributable to noncontrolling interest | 170 | 94 | [1] | 334 | 156 | |||
Net income attributable to partners | 432 | 202 | [1] | 1,147 | 533 | |||
Other comprehensive income, net of tax | 2 | (1) | [1] | 3 | (1) | |||
Comprehensive income | 604 | 295 | [1] | 1,484 | 688 | |||
Less: Comprehensive income attributable to noncontrolling interest | 170 | 94 | [1] | 334 | 156 | |||
Comprehensive income attributable to partners | 434 | 201 | [1] | 1,150 | 532 | |||
Parent Guarantor [Member] | ||||||||
Revenues | 0 | 0 | 0 | 0 | ||||
Costs and Expenses | 0 | 0 | 0 | 0 | ||||
OPERATING INCOME | 0 | 0 | 0 | 0 | ||||
Interest Expense | (289) | 0 | (567) | 0 | ||||
Equity in earnings (losses) of unconsolidated affiliates | 701 | 199 | 1,642 | 1,010 | ||||
Gains (losses) on interest rate derivatives | 20 | 0 | 72 | 0 | ||||
Deconsolidation, Gain (Loss), Amount | 0 | 0 | ||||||
Gain on Sunoco LP common unit repurchase | 0 | |||||||
Other Nonoperating Income (Expense) | 0 | 0 | 0 | 0 | ||||
Income (Loss) Attributable to Parent, before Tax | 432 | 199 | 1,147 | 1,010 | ||||
Income tax expense | 0 | 0 | 0 | 0 | ||||
Net income | 432 | 199 | 1,147 | 1,010 | ||||
Less: Net income attributable to noncontrolling interest | 0 | 0 | 0 | 0 | ||||
Net income attributable to partners | 432 | 199 | 1,147 | 1,010 | ||||
Other comprehensive income, net of tax | 0 | 0 | 0 | 0 | ||||
Comprehensive income | 432 | 199 | 1,147 | 1,010 | ||||
Less: Comprehensive income attributable to noncontrolling interest | 0 | 0 | 0 | 0 | ||||
Comprehensive income attributable to partners | 432 | 199 | 1,147 | 1,010 | ||||
Subsidiary Issuer [Member] | ||||||||
Revenues | 0 | 0 | 0 | 0 | ||||
Costs and Expenses | 0 | 1 | 0 | 1 | ||||
OPERATING INCOME | 0 | (1) | 0 | (1) | ||||
Interest Expense | (41) | (39) | (82) | 81 | ||||
Equity in earnings (losses) of unconsolidated affiliates | 66 | 137 | 326 | 765 | ||||
Gains (losses) on interest rate derivatives | 0 | 0 | 0 | 0 | ||||
Deconsolidation, Gain (Loss), Amount | 0 | 0 | ||||||
Gain on Sunoco LP common unit repurchase | 0 | |||||||
Other Nonoperating Income (Expense) | 0 | 3 | 0 | 3 | ||||
Income (Loss) Attributable to Parent, before Tax | 25 | 100 | 244 | 686 | ||||
Income tax expense | 0 | 0 | 0 | 0 | ||||
Net income | 25 | 100 | 244 | 686 | ||||
Less: Net income attributable to noncontrolling interest | 0 | 0 | 0 | 0 | ||||
Net income attributable to partners | 25 | 100 | 244 | 686 | ||||
Other comprehensive income, net of tax | 0 | 0 | 0 | 0 | ||||
Comprehensive income | 25 | 100 | 244 | 686 | ||||
Less: Comprehensive income attributable to noncontrolling interest | 0 | 0 | 0 | 0 | ||||
Comprehensive income attributable to partners | 25 | 100 | 244 | 686 | ||||
Non-Guarantor Subsidiaries [Member] | ||||||||
Revenues | 9,410 | 6,576 | 17,690 | 13,471 | ||||
Costs and Expenses | 8,467 | 5,839 | 15,774 | 12,051 | ||||
OPERATING INCOME | 943 | 737 | 1,916 | 1,420 | ||||
Interest Expense | (28) | (297) | (55) | 587 | ||||
Equity in earnings (losses) of unconsolidated affiliates | 106 | (61) | 34 | 12 | ||||
Gains (losses) on interest rate derivatives | 0 | (25) | 0 | (20) | ||||
Deconsolidation, Gain (Loss), Amount | (86) | (86) | ||||||
Gain on Sunoco LP common unit repurchase | 172 | |||||||
Other Nonoperating Income (Expense) | 46 | 59 | 106 | 78 | ||||
Income (Loss) Attributable to Parent, before Tax | 981 | 413 | 2,087 | 903 | ||||
Income tax expense | 69 | 79 | 29 | 134 | ||||
Net income | 912 | 334 | 2,058 | 769 | ||||
Less: Net income attributable to noncontrolling interest | 170 | 94 | 334 | 156 | ||||
Net income attributable to partners | 742 | 240 | 1,724 | 613 | ||||
Other comprehensive income, net of tax | 2 | (1) | 3 | (1) | ||||
Comprehensive income | 914 | 333 | 2,061 | 768 | ||||
Less: Comprehensive income attributable to noncontrolling interest | 170 | 94 | 334 | 156 | ||||
Comprehensive income attributable to partners | 744 | 239 | 1,727 | 612 | ||||
Adjustments And Eliminations [Member] | ||||||||
Revenues | 0 | 0 | 0 | 0 | ||||
Costs and Expenses | 0 | 0 | 0 | 0 | ||||
OPERATING INCOME | 0 | 0 | 0 | 0 | ||||
Interest Expense | 0 | 0 | 0 | 0 | ||||
Equity in earnings (losses) of unconsolidated affiliates | (767) | (336) | (1,968) | (1,775) | ||||
Gains (losses) on interest rate derivatives | 0 | 0 | 0 | 0 | ||||
Deconsolidation, Gain (Loss), Amount | 0 | 0 | ||||||
Gain on Sunoco LP common unit repurchase | 0 | |||||||
Other Nonoperating Income (Expense) | 0 | (1) | 0 | (1) | ||||
Income (Loss) Attributable to Parent, before Tax | (767) | (337) | (1,968) | (1,776) | ||||
Income tax expense | 0 | 0 | 0 | 0 | ||||
Net income | (767) | (337) | (1,968) | (1,776) | ||||
Less: Net income attributable to noncontrolling interest | 0 | 0 | 0 | 0 | ||||
Net income attributable to partners | (767) | (337) | (1,968) | (1,776) | ||||
Other comprehensive income, net of tax | 0 | 0 | 0 | 0 | ||||
Comprehensive income | (767) | (337) | (1,968) | (1,776) | ||||
Less: Comprehensive income attributable to noncontrolling interest | 0 | 0 | 0 | 0 | ||||
Comprehensive income attributable to partners | $ (767) | $ (337) | $ (1,968) | $ (1,776) | ||||
|
Guarantor Financial Information Cash Flows (Details) - USD ($) $ in Millions |
6 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|||||
Net Cash Provided by (Used in) Operating Activities | $ 2,950 | $ 1,650 | [1] | |||||
Net Cash Provided by (Used in) Investing Activities | (1,591) | (1,486) | [1] | |||||
Net Cash Provided by (Used in) Financing Activities | (1,171) | (252) | [1] | |||||
Cash and Cash Equivalents, Period Increase (Decrease) | 188 | (88) | [1] | |||||
Cash and Cash Equivalents, at Carrying Value | 494 | 272 | [1] | $ 306 | $ 360 | [1] | ||
Parent Guarantor [Member] | ||||||||
Net Cash Provided by (Used in) Operating Activities | 3,252 | 1,010 | ||||||
Net Cash Provided by (Used in) Investing Activities | (2,925) | (716) | ||||||
Net Cash Provided by (Used in) Financing Activities | (327) | (294) | ||||||
Cash and Cash Equivalents, Period Increase (Decrease) | 0 | 0 | ||||||
Cash and Cash Equivalents, at Carrying Value | 0 | 0 | 0 | 0 | ||||
Subsidiary Issuer [Member] | ||||||||
Net Cash Provided by (Used in) Operating Activities | 102 | 652 | ||||||
Net Cash Provided by (Used in) Investing Activities | (99) | (421) | ||||||
Net Cash Provided by (Used in) Financing Activities | 0 | (249) | ||||||
Cash and Cash Equivalents, Period Increase (Decrease) | 3 | (18) | ||||||
Cash and Cash Equivalents, at Carrying Value | 0 | 23 | (3) | 41 | ||||
Non-Guarantor Subsidiaries [Member] | ||||||||
Net Cash Provided by (Used in) Operating Activities | 585 | 1,764 | ||||||
Net Cash Provided by (Used in) Investing Activities | (903) | (2,125) | ||||||
Net Cash Provided by (Used in) Financing Activities | 503 | 291 | ||||||
Cash and Cash Equivalents, Period Increase (Decrease) | 185 | (70) | ||||||
Cash and Cash Equivalents, at Carrying Value | 494 | 249 | 309 | 319 | ||||
Adjustments And Eliminations [Member] | ||||||||
Net Cash Provided by (Used in) Operating Activities | (989) | (1,776) | ||||||
Net Cash Provided by (Used in) Investing Activities | 2,336 | 1,776 | ||||||
Net Cash Provided by (Used in) Financing Activities | (1,347) | 0 | ||||||
Cash and Cash Equivalents, Period Increase (Decrease) | 0 | 0 | ||||||
Cash and Cash Equivalents, at Carrying Value | $ 0 | $ 0 | $ 0 | $ 0 | ||||
|
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