Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 19, 2016 | Jun. 30, 2015 | |
Document Information [Line Items] | |||
Entity Current Reporting Status | Yes | ||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Entity Registrant Name | Energy Transfer Partners, L.P. | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Central Index Key | 1,012,569 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 507,740,653 | ||
Entity Public Float | $ 24,430 | ||
Entity Common Stock, Shares Outstanding | 2,015 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 527 | $ 663 |
Accounts receivable, net | 2,118 | 3,360 |
Accounts receivable from related companies | 268 | 139 |
Inventories | 1,213 | 1,460 |
Exchanges receivable | 30 | 44 |
Derivative assets | 40 | 81 |
Other current assets | 502 | 282 |
Total current assets | 4,698 | 6,029 |
Property, plant and equipment | 50,869 | 43,404 |
Accumulated depreciation and depletion | (5,782) | (4,497) |
PROPERTY, PLANT AND EQUIPMENT, net | 45,087 | 38,907 |
Advances to and investments in unconsolidated affiliates | 5,003 | 3,760 |
Non-current derivative assets | 0 | 10 |
Other non-current assets, net | 536 | 644 |
Intangible assets, net | 4,421 | 5,526 |
Goodwill | 5,428 | 7,642 |
Total assets | 65,173 | 62,518 |
Current liabilities: | ||
Accounts payable | 1,859 | 3,348 |
Accounts payable to related companies | 25 | 25 |
Exchanges payable | 105 | 183 |
Derivative liabilities | 63 | 21 |
Accrued and other current liabilities | 1,943 | 2,000 |
Current maturities of long-term debt | 126 | 1,008 |
Total current liabilities | 4,121 | 6,585 |
Long-term debt, less current maturities | 28,553 | 24,831 |
Long-term notes payable – related company | 233 | 0 |
Non-current derivative liabilities | 137 | 154 |
Deferred income taxes | 4,082 | 4,331 |
Other non-current liabilities | 968 | 1,258 |
Series A Preferred Units | 33 | 33 |
Redeemable noncontrolling interests | 15 | 15 |
Equity: | ||
General Partner | 306 | 184 |
Limited Partners: | ||
Common Unitholders (505,645,703 and 355,510,227 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively) | 17,043 | 10,430 |
Class E Unitholders (8,853,832 units authorized, issued and outstanding – held by subsidiary) | 0 | 0 |
Class G Unitholders (90,706,000 units authorized, issued and outstanding – held by subsidiary) | 0 | 0 |
Class H Unitholders (81,001,069 and 50,160,000 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively) | 3,469 | 1,512 |
Class I Unitholders (100 units authorized, issued and outstanding) | 14 | 0 |
Accumulated other comprehensive income (loss) | 4 | (56) |
Total partners’ capital | 20,836 | 12,070 |
Noncontrolling interest | 6,195 | 5,153 |
Predecessor Equity | 0 | 8,088 |
Total equity | 27,031 | 25,311 |
Total liabilities and equity | $ 65,173 | $ 62,518 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2015 | Dec. 31, 2014 |
Common Units | ||
Units - Authorized | 505,645,703 | 355,510,227 |
Units - Issued | 505,645,703 | 355,510,227 |
Units - Outstanding | 505,645,703 | 355,510,227 |
Class E Units | ||
Units - Authorized | 8,853,832 | 8,853,832 |
Units - Issued | 8,853,832 | 8,853,832 |
Units - Outstanding | 8,853,832 | 8,853,832 |
Class G Units | ||
Units - Authorized | 90,706,000 | 90,706,000 |
Units - Issued | 90,706,000 | 90,706,000 |
Units - Outstanding | 90,706,000 | 90,706,000 |
Class H Units | ||
Units - Authorized | 81,001,069 | 50,160,000 |
Units - Issued | 81,001,069 | 50,160,000 |
Units - Outstanding | 81,001,069 | 50,160,000 |
Class I Units | ||
Units - Authorized | 100 | 0 |
Units - Issued | 100 | 0 |
Units - Outstanding | 100 | 0 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
REVENUES: | |||||
Natural gas sales | $ 3,671 | $ 5,386 | $ 3,842 | ||
NGL sales | 3,936 | 5,845 | 3,618 | ||
Crude sales | 8,378 | 16,416 | 15,477 | ||
Gathering, transportation and other fees | 3,997 | 3,517 | 3,097 | ||
Refined product sales | 9,958 | 19,437 | 18,479 | ||
Other | 4,352 | 4,874 | 3,822 | ||
Total revenues | 34,292 | 55,475 | 48,335 | ||
COSTS AND EXPENSES: | |||||
Cost of products sold | 27,029 | 48,414 | 42,580 | ||
Operating expenses | 2,261 | 2,059 | 1,669 | ||
Depreciation, depletion and amortization | 1,929 | 1,669 | 1,296 | ||
Selling, general and administrative | 475 | 520 | 482 | ||
Impairment losses | 339 | 370 | 689 | ||
Total costs and expenses | 32,033 | 53,032 | 46,716 | ||
OPERATING INCOME | 2,259 | 2,443 | 1,619 | ||
OTHER INCOME (EXPENSE): | |||||
Interest expense, net | (1,291) | (1,165) | (1,013) | ||
Equity in earnings from unconsolidated affiliates | 469 | 332 | 236 | ||
Gain on sale of AmeriGas common units | 0 | 177 | 87 | ||
Losses on extinguishments of debt | (43) | (25) | (7) | ||
Gains (losses) on interest rate derivatives | (18) | (157) | 44 | ||
Non-operating environmental remediation | 0 | 0 | (168) | ||
Other, net | 22 | (12) | 12 | ||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 1,398 | 1,593 | 810 | ||
Income tax expense (benefit) from continuing operations | (123) | [1] | 358 | [1] | 97 |
INCOME FROM CONTINUING OPERATIONS | 1,521 | 1,235 | 713 | ||
Income from discontinued operations | 0 | 64 | 33 | ||
NET INCOME | 1,521 | 1,299 | 746 | ||
Less: Net income attributable to noncontrolling interest | 157 | 116 | 255 | ||
Less: Net income (loss) attributable to predecessor | (34) | (153) | 35 | ||
NET INCOME ATTRIBUTABLE TO PARTNERS | 1,398 | 1,336 | 456 | ||
General Partner’s interest in net income | 1,064 | 513 | 506 | ||
Class H Unitholder’s interest in net income | 258 | 217 | 48 | ||
Class I Unitholder’s interest in net income | 94 | 0 | 0 | ||
Common Unitholders’ interest in net income (loss) | $ (18) | $ 606 | $ (98) | ||
INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT: | |||||
Basic income (loss) from continuing operations per Common Unit | $ (0.09) | $ 1.58 | $ (0.23) | ||
Diluted income (loss) from continuing operations per Common Unit | (0.10) | 1.58 | (0.23) | ||
NET INCOME (LOSS) PER COMMON UNIT: | |||||
Basic | (0.09) | 1.77 | (0.18) | ||
Diluted | $ (0.10) | $ 1.77 | $ (0.18) | ||
[1] | (2) Includes ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries. |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Net income | $ 1,521 | $ 1,299 | $ 746 |
Other comprehensive income (loss), net of tax: | |||
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges | 0 | 3 | (4) |
Change in value of derivative instruments accounted for as cash flow hedges | 0 | 0 | (1) |
Change in value of available-for-sale securities | (3) | 1 | 2 |
Actuarial gain (loss) relating to pension and other postretirement benefits | 65 | (113) | 66 |
Foreign currency translation adjustment | (1) | (2) | (1) |
Change in other comprehensive income from unconsolidated affiliates | (1) | (6) | 17 |
Total other comprehensive income | 60 | (117) | 79 |
Comprehensive income | 1,581 | 1,182 | 825 |
Less: Comprehensive income attributable to noncontrolling interest | 157 | 116 | 255 |
Less: Comprehensive income (loss) attributable to predecessor | (34) | (153) | 35 |
Comprehensive income attributable to partners | $ 1,458 | $ 1,219 | $ 535 |
CONSOLIDATED STATEMENT OF EQUIT
CONSOLIDATED STATEMENT OF EQUITY - USD ($) $ in Millions | Total | General Partner | Common Unitholders | Class H Units | Class I Units | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interest | Predecessor Equity |
Balance at Dec. 31, 2012 | $ 19,982 | $ 188 | $ 9,026 | $ 0 | $ 0 | $ (13) | $ 7,260 | $ 3,521 |
Increase (Decrease) in Unitholders' Equity | ||||||||
Distributions to partners | (1,802) | (523) | (1,228) | (51) | 0 | 0 | 0 | 0 |
Predecessor distributions to partners | (342) | 0 | 0 | 0 | 0 | 0 | 0 | (342) |
Distributions to noncontrolling interest | (303) | 0 | 0 | 0 | 0 | 0 | (303) | 0 |
Units issued for cash | 1,611 | 0 | 1,611 | 0 | 0 | 0 | 0 | 0 |
Predecessor units issued for cash | 149 | 0 | 0 | 0 | 0 | 0 | 0 | 149 |
Issuance of Class H Units | 0 | 0 | (1,514) | 1,514 | 0 | 0 | 0 | 0 |
Capital contributions from noncontrolling interest | 18 | 0 | 0 | 0 | 0 | 0 | 18 | 0 |
ETP Holdco Acquisition and SUGS Contribution | (1,440) | 0 | 2,013 | 0 | 0 | (5) | (3,448) | 0 |
Other comprehensive income, net of tax | 79 | 0 | 0 | 0 | 0 | 79 | 0 | 0 |
Other, net | (4) | 0 | (13) | 0 | 0 | 0 | (2) | 11 |
Net income | 746 | 506 | (98) | 48 | 0 | 0 | 255 | 35 |
Class H Unitholder’s interest in net income | 48 | |||||||
Net Income (Loss) Allocated to General Partners | (506) | |||||||
Less: Net income attributable to noncontrolling interest | 255 | |||||||
Balance at Dec. 31, 2013 | 18,694 | 171 | 9,797 | 1,511 | 0 | 61 | 3,780 | 3,374 |
Increase (Decrease) in Unitholders' Equity | ||||||||
Distributions to partners | (1,964) | (500) | (1,252) | (212) | 0 | 0 | 0 | 0 |
Predecessor distributions to partners | (645) | 0 | 0 | 0 | 0 | 0 | 0 | (645) |
Distributions to noncontrolling interest | (241) | 0 | 0 | 0 | 0 | 0 | (241) | 0 |
Units issued for cash | 1,382 | 0 | 1,382 | 0 | 0 | 0 | 0 | 0 |
Predecessor units issued for cash | 1,227 | 0 | 0 | 0 | 0 | 0 | 0 | 1,227 |
Capital contributions from noncontrolling interest | 67 | 0 | 0 | 0 | 0 | 0 | 67 | 0 |
Predecessor equity issued for acquisitions, net of cash received | Hoover Midstream Acquisition [Member] | 4,281 | 0 | 0 | 0 | 0 | 0 | 0 | 4,281 |
Susser Merger | Susser Merger [Member] | 1,534 | 0 | 908 | 0 | 0 | 0 | 626 | 0 |
Subsidiary units issued for cash | 1,244 | 1 | 174 | 0 | 0 | 0 | 1,069 | 0 |
Lake Charles LNG Transaction | Lake Charles LNG Transaction [Member] | (1,167) | 0 | (1,167) | 0 | 0 | 0 | 0 | 0 |
Acquisition and disposition of noncontrolling interest | (325) | (1) | (79) | 0 | 0 | 0 | (245) | 0 |
Other comprehensive income, net of tax | (117) | 0 | 0 | 0 | 0 | (117) | 0 | 0 |
Other, net | 42 | 0 | 61 | (4) | 0 | 0 | (19) | 4 |
Net income | 1,299 | 513 | 606 | 217 | 0 | 0 | 116 | (153) |
Class H Unitholder’s interest in net income | 217 | |||||||
Net Income (Loss) Allocated to General Partners | (513) | |||||||
Less: Net income attributable to noncontrolling interest | 116 | |||||||
Balance at Dec. 31, 2014 | 25,311 | 184 | 10,430 | 1,512 | 0 | (56) | 5,153 | 8,088 |
Increase (Decrease) in Unitholders' Equity | ||||||||
Distributions to partners | (3,134) | (944) | (1,863) | (247) | (80) | 0 | 0 | 0 |
Predecessor distributions to partners | (202) | 0 | 0 | 0 | 0 | 0 | 0 | (202) |
Distributions to noncontrolling interest | (338) | 0 | 0 | 0 | 0 | 0 | (338) | 0 |
Units issued for cash | 1,428 | 0 | 1,428 | 0 | 0 | 0 | 0 | 0 |
Predecessor units issued for cash | 34 | 0 | 0 | 0 | 0 | 0 | 0 | 34 |
Capital contributions from noncontrolling interest | 875 | 0 | 0 | 0 | 0 | 0 | 875 | 0 |
Subsidiary units issued for cash | 1,519 | 2 | 298 | 0 | 0 | 0 | 1,219 | 0 |
Regency Merger | 0 | 0 | 7,890 | 0 | 0 | 0 | 0 | (7,890) |
Exchange of equity and Controlling Interest in a Subsidiary | Bakken Pipeline Transaction [Member] | 1,019 | 0 | (999) | 1,946 | 0 | 0 | 72 | 0 |
Exchange of equity and Controlling Interest in a Subsidiary | Sunoco LP Exchange [Member] | (992) | 0 | (52) | 0 | 0 | 0 | (940) | 0 |
Exchange of equity and Controlling Interest in a Subsidiary | Susser Exchange Transaction [Member] | (68) | 0 | (68) | 0 | 0 | 0 | 0 | 0 |
Acquisition and disposition of noncontrolling interest | (65) | 0 | (26) | 0 | 0 | 0 | (39) | 0 |
Other comprehensive income, net of tax | 60 | 0 | 0 | 0 | 0 | 60 | 0 | 0 |
Other, net | 63 | 0 | 23 | 0 | 0 | 0 | 36 | 4 |
Net income | 1,521 | 1,064 | (18) | 258 | 94 | 0 | 157 | (34) |
Class H Unitholder’s interest in net income | 258 | |||||||
Net Income (Loss) Allocated to General Partners | (1,064) | |||||||
Less: Net income attributable to noncontrolling interest | 157 | |||||||
Balance at Dec. 31, 2015 | $ 27,031 | $ 306 | $ 17,043 | $ 3,469 | $ 14 | $ 4 | $ 6,195 | $ 0 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income | $ 1,521 | $ 1,299 | $ 746 |
Reconciliation of net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 1,929 | 1,669 | 1,296 |
Deferred income taxes | 202 | (49) | 48 |
Amortization included in interest expense | (36) | (60) | (72) |
Inventory valuation adjustments | 104 | 473 | (3) |
Unit-based compensation expense | 79 | 68 | 54 |
Impairment losses | 339 | 370 | 689 |
Gain on sale of AmeriGas common units | 0 | (177) | (87) |
Losses on extinguishments of debt | 43 | 25 | 7 |
Distributions on unvested awards | (16) | (16) | (12) |
Equity in earnings of unconsolidated affiliates | (469) | (332) | (236) |
Distributions from unconsolidated affiliates | 440 | 291 | 313 |
Other non-cash | (22) | (72) | 42 |
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (1,367) | (320) | (158) |
Net cash provided by operating activities | 2,747 | 3,169 | 2,627 |
INVESTING ACTIVITIES: | |||
Proceeds from the sale of AmeriGas common units | 0 | 814 | 346 |
Cash transferred to ETE in connection with the Sunoco LP Exchange | (114) | 0 | 0 |
Cash paid for acquisition of a noncontrolling interest | (129) | (325) | 0 |
Cash paid for Susser Merger, net of cash received | 0 | 808 | 0 |
Cash paid for ETP Holdco Acquisition | 0 | 0 | (1,332) |
Cash paid for all other acquisitions | (675) | (472) | (405) |
Capital expenditures (excluding allowance for equity funds used during construction) | (9,098) | (5,213) | (3,469) |
Cash paid for all other acquisitions | 80 | 45 | 52 |
Contributions to unconsolidated affiliates | (45) | (399) | (3) |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 124 | 136 | 419 |
Proceeds from sale of discontinued operations | 0 | 77 | 1,008 |
Proceeds from the sale of assets | 23 | 61 | 68 |
Change in restricted cash | 19 | 172 | (348) |
Other | (16) | (18) | 21 |
Net cash used in investing activities | (7,820) | (6,692) | (3,643) |
FINANCING ACTIVITIES: | |||
Proceeds from borrowings | 22,462 | 15,354 | 10,854 |
Repayments of long-term debt | (17,843) | (12,702) | (8,700) |
Proceeds from borrowings from affiliates | 233 | 0 | 0 |
Repayments of borrowings from affiliates | 0 | 0 | (166) |
Units issued for cash | 1,428 | 1,382 | 1,611 |
Predecessor Equity Offerings, Net of Issue Costs | 34 | 1,227 | 149 |
Subsidiary equity offerings, net of issue costs | 1,519 | 1,244 | 0 |
Capital contributions from noncontrolling interest | 841 | 67 | 18 |
Distribution Made to Limited Partner, Cash Distributions Paid | 3,134 | 1,964 | 1,802 |
Cash Outflow of Distributions to Predecessor Partners | (202) | (645) | (342) |
Distributions to noncontrolling interest | (338) | (241) | (303) |
Debt issuance costs | (63) | (63) | (57) |
Other | 0 | (41) | (42) |
Net cash provided by financing activities | 4,937 | 3,618 | 1,220 |
Increase (decrease) in cash and cash equivalents | (136) | 95 | 204 |
Cash and cash equivalents, beginning of period | 663 | 568 | 364 |
Cash and cash equivalents, end of period | 527 | 663 | 568 |
Bakken Pipeline Transaction [Member] | |||
INVESTING ACTIVITIES: | |||
Cash received for sale of noncontrolling interest | 980 | 0 | 0 |
Susser Exchange Transaction [Member] | |||
INVESTING ACTIVITIES: | |||
Cash received for sale of noncontrolling interest | 967 | 0 | 0 |
Rover Pipeline Sale [Member] | |||
INVESTING ACTIVITIES: | |||
Cash received for sale of noncontrolling interest | 64 | 0 | 0 |
Eagle Rock Midstream Acquisition [Member] | |||
INVESTING ACTIVITIES: | |||
Cash paid for predecessor acquisitions, net of cash received | $ 0 | $ (762) | $ 0 |
Operations and Organization (No
Operations and Organization (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Operations And Organization [Abstract] | |
OPERATIONS AND ORGANIZATION | OPERATIONS AND BASIS OF PRESENTATION: Organization. The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P. and its subsidiaries (the “Partnership” “we” or “ETP”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner. The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales. The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States. The Partnership owns a controlling interest in Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of crude oil, NGL and refined products pipelines. The Partnership owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. In November 2015, the Partnership and certain of its subsidiaries entered into a contribution agreement with Sunoco LP and certain of its subsidiaries, pursuant to which the Partnership agreed to contribute to Sunoco LP the Partnership’s remaining 68.42% membership interest in Sunoco, LLC and 100% of the membership interests in Sunoco Retail LLC. Sunoco Retail LLC, which is expected to be formed prior to the closing of the contribution, is expected to own all of the Partnership’s remaining retail assets that are currently held by subsidiaries of Sunoco, Inc., along with certain other assets. In exchange, the Partnership expects to receive $2.03 billion in cash, subject to certain working capital adjustments, and 5.7 million Sunoco LP common units, which will be issued and sold to a subsidiary of the Partnership in private transactions exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended. The transaction will be effective January 1, 2016 and is expected to close in early March 2016. Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 21 million ETP common units owned by ETE. These operations were reported within the retail marketing segment. In connection with this transaction, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. Regency Merger. On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.4124 Partnership common units. ETP issued 172.2 million Partnership common units to Regency unitholders, including 15.5 million units issued to Partnership subsidiaries. The 1.9 million outstanding Regency series A preferred units were converted into corresponding new Partnership Series A Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years. The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger. ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor. Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the date the financial statements were issued. The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, these undivided interests are consolidated proportionately. |
Estimates, Significant Accounti
Estimates, Significant Accounting Policies and Balance Sheet Detials (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |
Estimates Significant Accounting Policies And Balance Sheet Detail Text Block | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. New Accounting Pronouncements 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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies. In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidation analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption was permitted. We expect to adopt this standard for the year ended December 31, 2016, and we do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which simplifies the presentation of debt issuance costs by requiring debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. ASU 2015-03 is effective for annual reporting periods after December 15, 2015, including interim periods within that reporting period, with early adoption permitted for financial statements that have not been previously issued. Upon adoption, ASU 2015-03 must be applied retrospectively to all prior reporting period presented. We adopted and applied this standard to all consolidated financial statements presented and there was not a material impact to our financial position or results of operations as a result of the adoption of this standard. In August 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805) - Simplifying the Accounting for Measurement-Period Adjustments. This update requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Additionally, this update requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Finally, this update requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in this update are effective for financial statements issued with fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance and prior period amounts have been reclassified to conform to the current period presentation. As a result of the early adoption and retrospective application of ASU 2015-17, $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements. Revenue Recognition Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Our intrastate transportation and storage and interstate transportation and storage segments’ results 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. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues. Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we 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, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer. In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations. Our retail marketing segment sells gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease with the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured. Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs. Cash, Cash Equivalents and Supplemental Cash Flow Information 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: Years Ended December 31, 2015 2014 2013 Accounts receivable $ 819 $ 600 $ (557 ) Accounts receivable from related companies (243 ) (22 ) 26 Inventories (351 ) 51 (254 ) Exchanges receivable 13 18 (8 ) Other current assets (191 ) 132 (58 ) Other non-current assets, net 188 (6 ) (45 ) Accounts payable (1,215 ) (851 ) 542 Accounts payable to related companies (160 ) 3 (143 ) Exchanges payable (78 ) (99 ) 128 Accrued and other current liabilities (5 ) (92 ) 211 Other non-current liabilities (219 ) (73 ) 147 Price risk management assets and liabilities, net 75 19 (147 ) Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (1,367 ) $ (320 ) $ (158 ) Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2015 2014 2013 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 896 $ 643 $ 226 Net gains from subsidiary common unit transactions 300 175 — NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the Regency Merger $ 9,250 $ — $ — Issuance of Class H Units in connection with the Bakken Pipeline Transaction 1,946 — — Issuance of Common Units in connection with the Susser Merger — 908 — Issuance of Common Units in connection with the ETP Holdco Acquisition — — 2,464 Issuance of Class H Units — — 1,514 Contribution of property, plant and equipment from noncontrolling interest 34 — — Long-term debt assumed and non-compete agreement notes payable issued in acquisitions — 564 — Predecessor equity issuances of common units in connection with Regency’s acquisitions — 4,281 — Long-term debt assumed or exchanged in Regency’s acquisitions — 2,386 — Redemption of Common Units in connection with the Bakken Pipeline Transaction 999 — — Redemption of Common Units in connection with the Sunoco LP Exchange 52 — — Redemption of Common Units in connection with the Lake Charles LNG Transaction — 1,167 — SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,467 $ 1,232 $ 1,049 Cash paid for income taxes 71 344 58 Accounts Receivable Our midstream, NGL and intrastate transportation and storage operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned for all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. Master setoff agreements are put in place with counterparties where appropriate to mitigate risk. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Based on that review, a letter of credit or other security may be required. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted. We have a concentration of customers in the electric and gas utility industries as well as oil and natural gas producers and municipalities. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness based upon pre-established standards consistent with FERC filed tariffs to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due. Our retail marketing segment extends credit to customers after a review of various credit indicators. Depending on the type of customer and its risk profile, security in the form of a cash deposit, letter of credit or mortgages may be required. Management records reserves for bad debt by computing a proportion of average write-off activity over the past five years in comparison to the outstanding balance in accounts receivable. This proportion is then applied to the accounts receivable balance at the end of the reporting period to calculate a current estimate of what is uncollectible. The allowance computation may then be adjusted to reflect input provided by the credit department and business line managers who may have specific knowledge of uncollectible items. The credit department and business line managers make the decision to write off an account, based on understanding of the potential collectability. We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets. Inventories Inventories consist principally of natural gas held in storage, crude oil, refined products and spare parts. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method. Inventories consisted of the following: December 31, 2015 2014 Natural gas and NGLs $ 415 $ 392 Crude oil 424 364 Refined products 104 392 Spare parts and other 270 312 Total inventories $ 1,213 $ 1,460 During the year ended December 31, 2015 , the Partnership recorded write-downs of $104 million on its crude oil, refined products and NGL inventories as a result of a decline in the market price of these products. The write-down was calculated based upon current replacement costs. 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. Exchanges Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average cost pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms. Other Current Assets Other current assets consisted of the following: December 31, 2015 2014 Deposits paid to vendors $ 74 $ 65 Income taxes receivable 291 17 Prepaid expenses and other 137 200 Total other current assets $ 502 $ 282 Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the liquids transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds. Components and useful lives of property, plant and equipment were as follows: December 31, 2015 2014 Land and improvements $ 686 $ 1,307 Buildings and improvements (1 to 45 years) 1,526 1,918 Pipelines and equipment (5 to 83 years) 33,148 27,164 Natural gas and NGL storage facilities (5 to 46 years) 391 1,215 Bulk storage, equipment and facilities (2 to 83 years) 2,853 2,583 Tanks and other equipment (5 to 40 years) 60 58 Retail equipment (2 to 99 years) 401 515 Vehicles (1 to 25 years) 220 203 Right of way (20 to 83 years) 2,573 2,445 Furniture and fixtures (2 to 25 years) 55 57 Linepack 61 119 Pad gas 44 44 Natural resources 484 454 Other (1 to 30 years) 523 979 Construction work-in-process 7,844 4,343 50,869 43,404 Less – Accumulated depreciation and depletion (5,782 ) (4,497 ) Property, plant and equipment, net $ 45,087 $ 38,907 We recognized the following amounts for the periods presented: Years Ended December 31, 2015 2014 2013 Depreciation and depletion expense $ 1,713 $ 1,457 $ 1,202 Capitalized interest, excluding AFUDC $ 163 $ 101 $ 45 Advances to and Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2015 2014 Unamortized financing costs (1) $ 11 $ 30 Regulatory assets 90 85 Deferred charges 198 220 Restricted funds 192 177 Other 45 132 Total other non-current assets, net $ 536 $ 644 (1) Includes unamortized financing costs related to the Partnership’s revolving credit facilities. Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies. Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 2015 December 31, 2014 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 4,601 $ (554 ) $ 5,067 $ (464 ) Patents (9 years) 48 (16 ) 48 (11 ) Trade Names (15 years) 66 (18 ) 556 (15 ) Other (1 to 15 years) 6 (3 ) 36 (7 ) Total amortizable intangible assets $ 4,721 $ (591 ) $ 5,707 $ (497 ) Non-amortizable intangible assets: Trademarks 291 — 316 — Total intangible assets $ 5,012 $ (591 ) $ 6,023 $ (497 ) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2015 2014 2013 Reported in depreciation, depletion and amortization $ 216 $ 212 $ 117 Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2016 $ 195 2017 195 2018 195 2019 193 2020 193 We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. In 2015, we recorded $24 million of intangible asset impairments related to the liquids transportation and services segment primarily due to an expected decrease in future cash flows. Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream Liquids Transportation and Services Investment in Sunoco Logistics Retail Marketing All Other Total Balance, December 31, 2013 $ 10 $ 1,195 $ 686 $ 432 $ 1,346 $ 1,445 $ 742 $ 5,856 Acquired — — 451 — 12 1,862 15 2,340 Disposed — (184 ) — — — — — (184 ) Impaired — — (370 ) — — — — (370 ) Balance, December 31, 2014 10 1,011 767 432 1,358 3,307 757 7,642 Reduction due to Sunoco LP deconsolidation — — — — — (2,018 ) — |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
ACQUISITIONS AND DIVESTITURE | ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: 2015 Transactions Sunoco LLC to Sunoco LP In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million . Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued $41 million of Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015. Susser to Sunoco LP In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million . The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries. Sunoco LP to ETE Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 21 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years , which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. In connection with this transaction, the Partnership deconsolidated Sunoco LP, including goodwill of $1.81 billion and intangible assets of $982 million related to Sunoco LP. The Partnership continues to hold 37.8 million Sunoco LP common units accounted for under the equity method. The results of Sunoco LP’s operations have not been presented as discontinued operations and Sunoco LP’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements. Sunoco, Inc. to Sunoco LP In November 2015, ETP and Sunoco LP announced ETP’s contribution to Sunoco LP of the remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion . Sunoco LP will pay ETP $2.03 billion in cash, subject to certain working capital adjustments, and will issue to ETP 5.7 million Sunoco LP common units. The transaction will be effective January 1, 2016 and is expected to close in March 2016. Bakken Pipeline In March 2015, ETE transferred 30.8 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. In October 2015, Sunoco Logistics completed the previously announced acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access, LLC and Energy Transfer Crude Oil Company, LLC, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction. Regency Merger On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.4124 Partnership common units. ETP issued 172.2 million Partnership common units to Regency unitholders, including 15.5 million units issued to Partnership subsidiaries. The 1.9 million outstanding Regency series A preferred units were converted into corresponding new Partnership Series A Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years. The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger. ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor. 2014 Transactions Susser Merger In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens our retail geographic footprint and provides synergy opportunities and a platform for future growth. In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations. Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE. Summary of Assets Acquired and Liabilities Assumed We accounted for the Susser Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. The following table summarizes the assets acquired and liabilities assumed recognized as of the merger date: Susser Total current assets $ 446 Property, plant and equipment 1,069 Goodwill (1) 1,734 Intangible assets 611 Other non-current assets 17 3,877 Total current liabilities 377 Long-term debt, less current maturities 564 Deferred income taxes 488 Other non-current liabilities 39 Noncontrolling interest 626 2,094 Total consideration 1,783 Cash received 67 Total consideration, net of cash received $ 1,716 (1) None of the goodwill is expected to be deductible for tax purposes. The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2014. Our consolidated statements of operations for the year ended December 31, 2014 reflected revenue and net income related to Susser of $2.32 billion and $105 million , respectively. No pro forma information has been presented, as the impact of these acquisitions was not material in relation to ETP’s consolidated results of operations. MACS to Sunoco LP In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units. Lake Charles LNG Transaction On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). This transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG, including goodwill of $184 million and intangible assets of $50 million related to Lake Charles LNG. The results of Lake Charles LNG’s operations have not been presented as discontinued operations and Lake Charles LNG’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements due to the continuing involvement among the entities. In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 8 . Panhandle Merger On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% senior notes due 2024, 8.25% senior notes due 2029 and the junior subordinated notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency ( 31.4 million common units and 6.3 million Class F Units, all of which have subsequently converted into ETP common units), and ETP ( 2.2 million Common Units). Regency’s Acquisition of PVR Partners, L.P. On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million , which was funded through borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million , respectively. The total purchase price was allocated as follows: Assets At March 21, 2014 Current assets $ 149 Property, plant and equipment 2,716 Investment in unconsolidated affiliates 62 Intangible assets (average useful life of 30 years) 2,717 Goodwill (1) 370 Other non-current assets 18 Total assets acquired 6,032 Liabilities Current liabilities 168 Long-term debt 1,788 Premium related to senior notes 99 Non-current liabilities 30 Total liabilities assumed 2,085 Net assets acquired $ 3,947 (1) None of the goodwill is expected to be deductible for tax purposes. The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. Regency’s Acquisition of Eagle Rock’s Midstream Business On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion , including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million , respectively. The total purchase price was allocated as follows: Assets At July 1, 2014 Current assets $ 120 Property, plant and equipment 1,295 Other non-current assets 4 Goodwill 49 Total assets acquired 1,468 Liabilities Current liabilities 116 Long-term debt 499 Other non-current liabilities 12 Total liabilities assumed 627 Net assets acquired $ 841 The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. 2013 Transactions Sale of Southern Union’s Distribution Operations In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union’s NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allowed a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division. In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million , subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million , subject to customary post-closing adjustments, and the assumption of $20 million of debt. The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations. The following table summarizes selected financial information related to Southern Union’s distribution operations in 2013 through MGE and NEG’s sale dates in September 2013 and December 2013, respectively: Year Ended December 31, 2013 Revenue from discontinued operations $ 415 Net income of discontinued operations, excluding effect of taxes and overhead allocations 65 Acquisition of ETE’s ETP Holdco Interest On April 30, 2013, ETP acquired ETE’s 60% interest in ETP Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “ETP Holdco Acquisition”). As a result, ETP now owns 100% of ETP Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled ETP Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control. |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 12 Months Ended |
Dec. 31, 2015 | |
Investments in and Advances to Affiliates, Schedule of Investments [Abstract] | |
Investments in and Advances to Affiliates, Schedule of Investments [Text Block] | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2015 and 2014 were as follows: December 31, 2015 2014 Citrus $ 1,739 $ 1,823 AmeriGas 80 94 FEP 115 130 MEP 660 695 HPC 402 422 Sunoco LP 1,380 — Others 627 596 Total $ 5,003 $ 3,760 Citrus ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. In 2012, we recorded our investment in Citrus at $2.0 billion , which exceeded our proportionate share of Citrus’ equity by $1.03 billion , all of which is treated as equity method goodwill due to the application of regulatory accounting. Our investment in Citrus is reflected in our interstate transportation and storage segment. AmeriGas In 2012, we received 29.6 million AmeriGas common units in connection with the contribution of our propane operations. During the years ended December 31, 2014 and 2013, we sold 18.9 million and 7.5 million AmeriGas common units, respectively, for net proceeds of $814 million and $346 million , respectively. Subsequent to the sales, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company and is reflected in the all other segment. FEP We have a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. MEP We own a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment. HPC We own a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Our investment in HPC is reflected in the intrastate transportation and storage segment. Sunoco LP Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from the Partnership. As a result, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. Our investment in Sunoco LP is reflected in the retail marketing segment. Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, AmeriGas, Citrus, FEP, HPC, MEP and Sunoco LP (on a 100% basis) for all periods presented: December 31, 2015 2014 Current assets $ 1,646 $ 889 Property, plant and equipment, net 12,611 10,520 Other assets 5,485 2,687 Total assets $ 19,742 $ 14,096 Current liabilities $ 1,517 $ 1,983 Non-current liabilities 10,428 7,359 Equity 7,797 4,754 Total liabilities and equity $ 19,742 $ 14,096 Years Ended December 31, 2015 2014 2013 Revenue $ 20,961 $ 4,925 $ 4,695 Operating income 1,620 1,071 1,197 Net income 894 577 699 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements. |
Net Income Per Limited Partner
Net Income Per Limited Partner Unit (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
NET INCOME PER LIMITED PARTNER UNIT | NET INCOME PER LIMITED PARTNER UNIT: The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit. Years Ended December 31, 2015 2014 2013 Income from continuing operations $ 1,521 $ 1,235 $ 713 Less: Income from continuing operations attributable to noncontrolling interest 157 116 239 Less: Income (loss) from continuing operations attributable to predecessor (34 ) (153 ) 35 Income from continuing operations, net of noncontrolling interest 1,398 1,272 439 General Partner’s interest in income from continuing operations 1,064 513 505 Class H Unitholder’s interest in income from continuing operations 258 217 — Class I Unitholder’s interest in income from continuing operations 94 — — Common Unitholders’ interest in income (loss) from continuing operations (18 ) 542 (66 ) Additional earnings allocated to General Partner (5 ) (4 ) (2 ) Distributions on employee unit awards, net of allocation to General Partner (16 ) (13 ) (10 ) Income (loss) from continuing operations available to Common Unitholders $ (39 ) $ 525 $ (78 ) Weighted average Common Units – basic 432.8 331.5 343.4 Basic income (loss) from continuing operations per Common Unit $ (0.09 ) $ 1.58 $ (0.23 ) Income (loss) from continuing operations available to Common Unitholders $ (39 ) $ 525 $ (78 ) Loss attributable to ETP Series A Preferred Units (6 ) — — Diluted income (loss) from continuing operations available to Common Unitholders $ (45 ) $ 525 $ (78 ) Weighted average Common Units – basic 432.8 331.5 343.4 Dilutive effect of unvested Unit Awards — 1.3 — Dilutive effect of Preferred Units 0.7 — — Weighted average Common Units – diluted 433.5 332.8 343.4 Diluted income (loss) from continuing operations per Common Unit $ (0.10 ) $ 1.58 $ (0.23 ) Basic income from discontinued operations per Common Unit $ — $ 0.19 $ 0.05 Diluted income from discontinued operations per Common Unit $ — $ 0.19 $ 0.05 |
Debt Obligations (Notes)
Debt Obligations (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Obligations [Abstract] | |
DEBT OBLIGATIONS | DEBT OBLIGATIONS: Our debt obligations consist of the following: December 31, 2015 2014 ETP Debt 5.95% Senior Notes due February 1, 2015 $ — $ 750 6.125% Senior Notes due February 15, 2017 400 400 2.5% Senior Notes due June 15, 2018 650 — 6.7% Senior Notes due July 1, 2018 600 600 9.7% Senior Notes due March 15, 2019 400 400 9.0% Senior Notes due April 15, 2019 450 450 5.75% Senior Notes due September 1, 2020 (assumed from Regency) 400 — 4.15% Senior Notes due October 1, 2020 1,050 700 6.5% Senior Notes due May 15, 2021 (assumed from Regency) 500 — 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 5.875% Senior Notes due March 1, 2022 (assumed from Regency) 900 — 5.0% Senior Notes due October 1, 2022 (assumed from Regency) 700 — 3.60% Senior Notes due February 1, 2023 800 800 5.5% Senior Notes due April 15, 2023 (assumed from Regency) 700 — 4.5% Senior Notes due November 1, 2023 (assumed from Regency) 600 — 4.9% Senior Notes due February 1, 2024 350 350 7.6% Senior Notes due February 1, 2024 277 277 4.05% Senior Notes due March 15, 2025 1,000 — 4.75% Senior Notes due January 15, 2026 1,000 — 8.25% Senior Notes due November 15, 2029 267 267 4.90% Senior Notes due March 15, 2035 500 — 6.625% Senior Notes due October 15, 2036 400 400 7.5% Senior Notes due July 1, 2038 550 550 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.15% Senior Notes due March 15, 2045 1,000 — 6.125% Senior Notes due December 15, 2045 1,000 — Floating Rate Junior Subordinated Notes due November 1, 2066 545 546 ETP $3.75 billion Revolving Credit Facility due November 2019 1,362 570 Unamortized premiums, discounts and fair value adjustments, net (21 ) (1 ) Deferred debt issuance costs (147 ) (55 ) 20,633 11,404 Transwestern Debt 5.54% Senior Notes due November 17, 2016 125 125 5.64% Senior Notes due May 24, 2017 82 82 5.36% Senior Notes due December 9, 2020 175 175 5.89% Senior Notes due May 24, 2022 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 Unamortized premiums, discounts and fair value adjustments, net (1 ) (1 ) Deferred debt issuance costs (2 ) (3 ) 779 778 Panhandle Debt 6.20% Senior Notes due November 1, 2017 300 300 7.00% Senior Notes due June 15, 2018 400 400 8.125% Senior Notes due June 1, 2019 150 150 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 14, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 75 99 1,160 1,184 Sunoco, Inc. Debt 9.625% Senior Notes due April 15, 2015 — 250 5.75% Senior Notes due January 15, 2017 400 400 9.00% Debentures due November 1, 2024 65 65 Unamortized premiums, discounts and fair value adjustments, net 20 35 485 750 Sunoco Logistics Debt 6.125% Senior Notes due May 15, 2016 (1) 175 175 5.50% Senior Notes due February 15, 2020 250 250 4.4% Senior Notes due April 1, 2021 600 — 4.65% Senior Notes due February 15, 2022 300 300 3.45% Senior Notes due January 15, 2023 350 350 4.25% Senior Notes due April 1, 2024 500 500 5.95% Senior Notes due December 1, 2025 400 — 6.85% Senior Notes due February 15, 2040 250 250 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.30% Senior Notes due April 1, 2044 700 700 5.35% Senior Notes due May 15, 2045 800 800 Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015 (2) — 35 Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 562 150 Unamortized premiums, discounts and fair value adjustments, net 85 100 Deferred debt issuance costs (32 ) (26 ) 5,590 4,234 Sunoco LP Debt (3) — 683 Regency Debt, net of deferred debt issuance costs of $58 million (4) — 6,583 Other 32 223 28,679 25,839 Less: current maturities 126 1,008 $ 28,553 $ 24,831 (1) Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of December 31, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. (2) Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility matured in April 2015 and was repaid with borrowings from the Sunoco Logistics $2.50 billion Revolving Credit Facility. (3) In connection with ETE’s acquisition of Sunoco GP, the general partner of Sunoco LP, on July 1, 2015, ETP deconsolidated Sunoco LP. (4) As discussed below, the Regency senior notes were redeemed and/or assumed by the Partnership. On April 30, 2015, in connection with the Regency Merger, the Regency Revolving Credit Facility was paid off in full and terminated. The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $23 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: 2016 $ 301 2017 1,182 2018 1,650 2019 2,362 2020 2,937 Thereafter 20,270 Total $ 28,702 Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap. ETP as Co-Obligor of Sunoco, Inc. Debt In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $465 million as of December 31, 2015 . ETP Senior Notes The ETP senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually. The ETP senior notes are unsecured obligations of the Partnership and the obligation of the Partnership to repay the ETP senior notes is not guaranteed by any of the Partnership’s subsidiaries. As a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries. In June 2015, ETP issued $650 million aggregate principal amount of 2.50% senior notes due June 2018 , $350 million aggregate principal amount of 4.15% senior notes due October 2020 , $1.0 billion aggregate principal amount of 4.75% senior notes due January 2026 and $1.0 billion aggregate principal amount of 6.125% senior notes due December 2045 . ETP used the net proceeds of $2.98 billion from the offering to repay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes. In March 2015, ETP issued $1.0 billion aggregate principal amount of 4.05% senior notes due March 2025 , $500 million aggregate principal amount of 4.90% senior notes due March 2035 , and $1.0 billion aggregate principal amount of 5.15% senior notes due March 2045 . ETP used the $2.48 billion net proceeds from the offering to repay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes. At the time of the Regency Merger, Regency had outstanding $5.1 billion principal amount of senior notes. On June 1, 2015, Regency redeemed all of the outstanding $499 million aggregate principal amount of its 8.375% senior notes due June 2019 . Panhandle previously agreed to fully and unconditionally guarantee (the “Panhandle Guarantee”) all of the payment obligations of Regency and Regency Energy Finance Corp. under their $600 million in aggregate principal amount of 4.50% senior notes due November 2023 . On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it became a co-obligor with respect to such payment obligations thereunder. Accordingly, pursuant to the terms of such supplemental indentures the Panhandle Guarantee was terminated. On August 10, 2015, ETP entered into various supplemental indentures pursuant to which ETP has agreed to assume all of the obligations of Regency under the following series of outstanding senior notes of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor: • $400 million in aggregate principal amount of 5.750% Senior Notes due 2020; • $390 million in aggregate principal amount of 8.375% Senior Notes due 2020 (the “2020 Notes”); • $260 million in aggregate principal amount of 6.500% Senior Notes due 2021 (the “2021 Notes”); • $500 million in aggregate principal amount of 6.500% Senior Notes due 2021; • $700 million in aggregate principal amount of 5.000% Senior Notes due 2022; • $900 million in aggregate principal amount of 5.875% Senior Notes due 2022; • $600 million in aggregate principal amount of 4.500% Senior Notes due 2023; and • $700 million in aggregate principal amount of 5.500% Senior Notes due 2023. The notes assumed from Regency are registered under the Securities Act of 1933 (as amended). The senior notes assumed from Regency may be redeemed at any time, or from time to time, pursuant to the terms of the applicable indenture and related indenture supplements related to the Regency senior notes. The balance is payable upon maturity and interest is payable semi-annually. The indentures on these notes contain various covenants that are similar to those of the indentures on ETP’s senior notes. The senior notes assumed from Regency are fully and unconditionally guaranteed, on a joint and several basis, by all of the consolidated subsidiaries that were previously consolidated by Regency, except for ELG and its wholly-owned subsidiaries, Aqua – PVR and ORS. On August 13, 2015, ETP redeemed in full the outstanding amount of the 2020 Notes and the 2021 Notes. The amount paid to redeem the 2020 Notes included a make whole premium of $40 million and the amount paid to redeem the 2021 Notes included a make whole premium of $24 million . Transwestern Senior Notes The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually. Panhandle Junior Subordinated Notes The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175% . The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.65% at December 31, 2015 . Sunoco Logistics Senior Notes Offerings In November 2015, Sunoco Logistics issued $600 million aggregate principal amount of 4.40% senior notes due April 2021 and $400 million aggregate principal amount of 5.95% senior notes due December 2025. Credit Facilities ETP Credit Facility The ETP Credit Facility allows for borrowings of up to $3.75 billion and expires in November 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt. We use the ETP Credit Facility to provide temporary financing for our growth projects, as well as for general partnership purposes. As of December 31, 2015 , the ETP Credit Facility had $1.36 billion outstanding, and the amount available for future borrowings was $2.24 billion after taking into account letters of credit of $145 million . The weighted average interest rate on the total amount outstanding as of December 31, 2015 was 1.86% . Sunoco Logistics Credit Facilities Sunoco Logistics maintains a $2.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $3.25 billion under certain conditions. The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2015 , the Sunoco Logistics Credit Facility had $562 million of outstanding borrowings. Covenants Related to Our Credit Agreements Covenants Related to ETP The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things: • incur indebtedness; • grant liens; • enter into mergers; • dispose of assets; • make certain investments; • make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement); • engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; • engage in transactions with affiliates; and • enter into restrictive agreements. The credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility. The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio. Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions. Covenants Related to Panhandle Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants. Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries. In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt. Covenants Related to Sunoco Logistics Sunoco Logistics’ $2.50 billion credit facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants related to the operation and conduct of the business of Sunoco Logistics and its subsidiaries. The credit facility also limits Sunoco Logistics, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1 , which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total consolidated debt, excluding net unamortized fair value adjustments, to consolidated Adjusted EBITDA was 3.6 to 1 at December 31, 2015 , as calculated in accordance with the credit agreements. Compliance with our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2015 . |
Series A Preferred Units (Notes
Series A Preferred Units (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Temporary Equity Disclosure [Abstract] | |
Preferred Units [Text Block] | SERIES A PREFERRED UNITS: In connection with the closing of the Regency Merger, Regency’s 1.9 million outstanding series A cumulative convertible preferred units were converted into corresponding newly issued ETP cumulative convertible series A preferred units on a one-for-one basis. If outstanding, the Preferred Units are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in our consolidated balance sheets. The Preferred Units are entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record dates of the Partnership’s common unit distributions. Holders of the Preferred Units can elect to convert the ETP Preferred Units to ETP Common Units at any time in accordance with ETP’s partnership agreement. The number of common units issuable upon conversion of the Preferred Units is equal to the issue price of $18.30 , plus all accrued but unpaid distributions and interest thereon, divided by the conversion price of $44.37 . As of December 31, 2015 , the Preferred Units were convertible into 0.9 million ETP Common Units. |
Equity (Notes)
Equity (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
EQUITY | EQUITY: Limited Partner interests are represented by Common, Class E Units, Class G Units, Class H and Class I Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance. IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs. Common Units The change in Common Units was as follows: Years Ended December 31, 2015 2014 2013 Number of Common Units, beginning of period 355.5 333.8 301.5 Common Units redeemed in connection with certain transactions (51.8 ) (18.7 ) — Common Units issued in connection with public offerings — — 13.8 Common Units issued in connection with certain acquisitions 172.2 15.8 49.5 Common Units redeemed for Class H Units — — (50.2 ) Common Units issued in connection with the Distribution Reinvestment Plan 7.7 2.8 2.3 Common Units issued in connection with Equity Distribution Agreements 21.1 21.4 16.9 Repurchases of Common Units in open-market transactions — — (0.4 ) Issuance of Common Units under equity incentive plans 0.9 0.4 0.4 Number of Common Units, end of period 505.6 355.5 333.8 Our Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.” Public Offerings In April 2013 , the Partnership completed a public offerings of 13.8 million Common Units, all of which have been registered under the Securities Act of 1933 (as amended), for net proceeds of $657 million . Proceeds were used to repay amounts outstanding under the ETP Credit Facility and for general partnership purposes. Equity Distribution Program From time to time, we have sold Common Units through equity distribution agreements. Such sales of Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreements. During the year ended December 31, 2015 , we issued 21.1 million units for $1.07 billion , net of commissions of $11 million . As of December 31, 2015 , $328 million of our Common Units remained available to be issued under our currently effective equity distribution agreement. Equity Incentive Plan Activity We issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations. Distribution Reinvestment Program Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. During the years ended December 31, 2015 , 2014 and 2013 , aggregate distributions of $360 million , $155 million , and $109 million , respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 12.8 million Common Units. In December, 2015, we provided notice to the DRIP participants that we have changed the discount at which participants may purchase ETP common units through the DRIP from 5% to 1% , effective for the distributions payable in respect of the fourth quarter of 2015 and future quarters. As of December 31, 2015 , a total of 11.5 million Common Units remain available to be issued under the existing registration statement. Class E Units The Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to Unitholders other than the holders of Class E Units in proportion to their respective interests. The Class E Units are treated as treasury units for accounting purposes because they are owned by a subsidiary of ETP Holdco, Heritage Holdings, Inc. Although no plans are currently in place, management may evaluate whether to retire some or all of the Class E Units at a future date. All of the 8.9 million Class E Units outstanding are held by a subsidiary and are reported as treasury units. Class G Units In conjunction with the Sunoco Merger, we amended our partnership agreement to create Class F Units. The number of Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million , which included 40 million Class F Units issued in exchange for cash contributed by Sunoco, Inc. to us immediately prior to or concurrent with the closing of the Sunoco Merger. The Class F Units generally did not have any voting rights. The Class F Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class F Unit per year. In April 2013, all of the outstanding Class F Units were exchanged for Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in the consolidated financial statements. Class H Units and Class I Units Currently Outstanding Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. Bakken Pipeline Transaction In March 2015, ETE transferred 30.8 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. In connection with the transaction, ETP issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ending March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Sales of Common Units by Sunoco Logistics With respect to our investment in Sunoco Logistics, we account for the difference between the carrying amount of our investment in and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions. As a result of Sunoco Logistics’ issuances of common units during the year ended December 31, 2015 , we recognized increases in partners’ capital of $300 million . In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion . In the fourth quarter of 2015, the aggregate capacity was increased to $2.25 billion . During the year ended December 31, 2015 , Sunoco Logistics received proceeds of $890 million , net of commissions of $10 million , from the issuance of 26.8 million common units pursuant to the equity distribution agreement, which were used for general partnership purposes. In March 2015, Sunoco Logistics completed a public offering of 13.5 million common units for net proceeds of $547 million . The proceeds were used to repay outstanding borrowings under the $2.5 billion Sunoco Logistics Credit Facility and for general partnership purposes. In April 2015, an additional 2.0 million common units were issued for net proceeds of $82 million related to the exercise of an option in connection with the March 2015 offering. In September 2014, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million were used to repay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes. Quarterly Distributions of Available Cash The Partnership Agreement requires that we distribute all of our Available Cash to our Unitholders and our General Partner within forty-five days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any of our fiscal quarters, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partner in its sole discretion to provide for the proper conduct of our business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in our Partnership Agreement. Our distributions of Available Cash from operating surplus, excluding incentive distributions, to our General Partner and Limited Partner interests are based on their respective interests as of the distribution record date. Incentive distributions allocated to our General Partner are determined based on the amount by which quarterly distribution to common Unitholders exceed certain specified target levels, as set forth in our Partnership Agreement. Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2012 February 7, 2013 February 14, 2013 $ 0.8938 March 31, 2013 May 6, 2013 May 15, 2013 0.8938 June 30, 2013 August 5, 2013 August 14, 2013 0.8938 September 30, 2013 November 4, 2013 November 14, 2013 0.9050 December 31, 2013 February 7, 2014 February 14, 2014 0.9200 March 31, 2014 May 5, 2014 May 15, 2014 0.9350 June 30, 2014 August 4, 2014 August 14, 2014 0.9550 September 30, 2014 November 3, 2014 November 14, 2014 0.9750 December 31, 2014 February 6, 2015 February 13, 2015 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 September 30, 2015 November 5, 2015 November 16, 2015 1.0550 December 31, 2015 February 8, 2016 February 16, 2016 1.0550 ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units: Total Year 2016 $ 137 2017 128 2018 105 2019 95 Sunoco Logistics Quarterly Distributions of Available Cash Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2012 February 8, 2013 February 14, 2013 $ 0.2725 March 31, 2013 May 9, 2013 May 15, 2013 0.2863 June 30, 2013 August 8, 2013 August 14, 2013 0.3000 September 30, 2013 November 8, 2013 November 14, 2013 0.3150 December 31, 2013 February 10, 2014 February 14, 2014 0.3312 March 31, 2014 May 9, 2014 May 15, 2014 0.3475 June 30, 2014 August 8, 2014 August 14, 2014 0.3650 September 30, 2014 November 7, 2014 November 14, 2014 0.3825 December 31, 2014 February 9, 2015 February 13, 2015 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380 September 30, 2015 November 9, 2015 November 13, 2015 0.4580 December 31, 2015 February 8, 2016 February 12, 2016 0.4790 Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: December 31, 2015 2014 Available-for-sale securities $ — $ 3 Foreign currency translation adjustment (4 ) (3 ) Net loss on commodity related hedges — (1 ) Actuarial gain (loss) related to pensions and other postretirement benefits 8 (57 ) Investments in unconsolidated affiliates, net — 2 Total AOCI, net of tax $ 4 $ (56 ) The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss): December 31, 2015 2014 Available-for-sale securities $ (2 ) $ (1 ) Foreign currency translation adjustment 4 2 Actuarial loss (gain) relating to pension and other postretirement benefits 7 (37 ) Total $ 9 $ (36 ) |
Unit-Based Compensation Plans (
Unit-Based Compensation Plans (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Deferred Compensation Arrangements [Abstract] | |
UNIT-BASED COMPENSATION PLANS | UNIT-BASED COMPENSATION PLANS: ETP Unit-Based Compensation Plan We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2015 , an aggregate total of 5.3 million ETP Common Units remain available to be awarded under our equity incentive plans. Restricted Units We have granted restricted unit awards to employees that vest over a specified time period, typically a five -year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five -year service vesting requirement. The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2014 3.5 $ 53.83 Awards granted 2.1 35.21 Awards vested (1.2 ) 48.67 Awards forfeited (0.4 ) 55.44 Conversion of RGP unit awards to ETP unit awards 0.8 58.88 Unvested awards as of December 31, 2015 4.8 47.61 During the years ended December 31, 2015, 2014, and 2013 , the weighted average grant-date fair value per unit award granted was $35.21 , $60.85 and $50.54 , respectively. The total fair value of awards vested was $49 million , $26 million and $29 million , respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2015 , a total of 4.8 million unit awards remain unvested, for which ETP expects to recognize a total of $147 million in compensation expense over a weighted average period of 2.1 years . Cash Restricted Units. The Partnership has also granted cash restricted units, which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. As of December 31, 2015 , a total of 0.6 million unvested cash restricted units were outstanding. Based on the trading price of ETP Common Units at December 31, 2015 , the Partnership expects to recognize $7 million of unit-based compensation expense related to non-vested cash restricted units over a period of 1.3 years . Sunoco Logistics Unit-Based Compensation Plan Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco Logistics. As of December 31, 2015 , a total of 2.5 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $52 million of expense over a weighted average period of 3 years . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | INCOME TAXES: As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows: Years Ended December 31, 2015 2014 2013 Current expense (benefit): Federal $ (274 ) $ 321 $ 51 State (51 ) 86 (2 ) Total (325 ) 407 49 Deferred expense (benefit): Federal 231 (50 ) (6 ) State (29 ) 1 54 Total 202 (49 ) 48 Total income tax expense (benefit) from continuing operations $ (123 ) $ 358 $ 97 Historically, our effective rate differed from the statutory rate primarily due to Partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3 ) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2015 , 2014 and 2013 is as follows: December 31, 2015 December 31, 2014 December 31, 2013 Corporate Subsidiaries (1) Consolidated (2) Corporate Subsidiaries (1) Consolidated (2) Corporate Subsidiaries (1) Consolidated (2) Income tax expense (benefit) at U.S. statutory rate of 35 percent $ (25 ) $ (25 ) $ 217 $ 217 $ (166 ) $ (166 ) Increase (reduction) in income taxes resulting from: Nondeductible goodwill — — — — 241 241 Nondeductible goodwill included in the Lake Charles LNG Transaction — — 105 105 — — State income taxes (net of federal income tax effects) (56 ) (37 ) 9 54 31 36 Dividend Received Deduction (24 ) (24 ) — — — — Premium on debt retirement — — (10 ) (10 ) — — Audit Settlement (7 ) (7 ) — — — — Foreign — — (8 ) (8 ) — — Other (30 ) (30 ) — — (13 ) (14 ) Income tax expense (benefit) from continuing operations $ (142 ) $ (123 ) $ 313 $ 358 $ 93 $ 97 (1) Includes ETP Holdco, Susser Holdings Corporation, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd., Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. Susser Holding Corporation, Susser Petroleum Property Company LLC and Aloha Petroleum Ltd. were deconsolidated from these financial statements in July 2015 due to the contribution of Susser Holding Corporation to Sunoco LP and the acquisition by ETE of 100% of the membership interest of Sunoco GP, the general partner of Sunoco LP (See Note 3 ). (2) Includes ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries. Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2015 2014 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 155 $ 116 Pension and other postretirement benefits 36 47 Long term debt 61 53 Other 142 111 Total deferred income tax assets 394 327 Valuation allowance (121 ) (84 ) Net deferred income tax assets $ 273 $ 243 Deferred income tax liabilities: Properties, plants and equipment $ (1,305 ) $ (1,506 ) Inventory — (153 ) Investment in unconsolidated affiliates (2,889 ) (2,528 ) Trademarks (112 ) (355 ) Other (49 ) (32 ) Total deferred income tax liabilities (4,355 ) (4,574 ) Accumulated deferred income taxes $ (4,082 ) $ (4,331 ) As a result of the early adoption and retrospective application of ASU 2015-17 (see Note 2 ), $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements. The deconsolidation of Susser Holding Corporation, Susser Petroleum Property Company LLC and Aloha Petroleum Ltd. in July 2015 due to the contribution of Susser Holding Corporation to Sunoco LP and the acquisition by ETE of 100% of the membership interest of Sunoco GP, the general partner of Sunoco LP (see Note 3 ) significantly decreased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows: December 31, 2015 2014 Net deferred income tax liability, beginning of year $ (4,331 ) $ (3,903 ) Susser acquisition — (488 ) ETE Acquisition of general partner of Sunoco LP 490 — Tax provision (including discontinued operations) (202 ) 60 Other (39 ) — Net deferred income tax liability, end of year $ (4,082 ) $ (4,331 ) ETP Holdco and other corporate subsidiaries have federal net operating loss carryforward tax benefits of $6 million , all of which will expire in 2032 through 2034 . Our corporate subsidiaries have $27 million of federal alternative minimum tax credits at December 31, 2015 . Our corporate subsidiaries have state net operating loss carryforward benefits of $122 million , net of federal tax, which expire between 2016 and 2035 . The valuation allowance of $121 million is applicable to the state net operating loss carryforward benefits primarily attributable to Sunoco, Inc.’s pre-acquisition periods. The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2015 2014 2013 Balance at beginning of year $ 440 $ 429 $ 27 Additions attributable to tax positions taken in the current year — 20 — Additions attributable to tax positions taken in prior years 178 (1 ) 406 Settlements — (5 ) — Lapse of statute (8 ) (3 ) (4 ) Balance at end of year $ 610 $ 440 $ 429 As of December 31, 2015 , we have $588 million ( $550 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $4 million ( $3 million , net of federal tax) within the next twelve months due to settlement of certain positions. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2015, we recognized interest and penalties of less than $1 million . At December 31, 2015, we have interest and penalties accrued of $5 million , net of tax. Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 open statute years, Sunoco, Inc. has proposed to the IRS that these government incentive payments be excluded from federal taxable income. If Sunoco, Inc. is fully successful with its claims, it will receive tax refunds of approximately $519 million . However, due to the uncertainty surrounding the claims, a reserve of $519 million was established for the full amount of the claims. Due to the timing of the expected settlement of the claims and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 2015 . In December of 2015, The Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“ Nextel ”) that the Pennsylvania limitation on NOL carryforwards violated the uniformity clause of the Pennsylvania Constitution. Based upon the decision in Nextel , Sunoco, Inc. is recognizing approximately $46 million ( $30 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims. However, as the Nextel decision is subject to appeal, and because of uncertainty in the breadth of the application of the decision, we have reserved $9 million ( $6 million after federal income tax benefits) against the receivable. In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2012 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007. Sunoco, Inc. has been examined by the IRS for tax years through 2012. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments. Southern Union was under examination by the IRS for the tax years 2004 through 2009. In July 2015, we and the IRS settled all issues related to the IRS examination of the 2004 through 2009 tax years. As a result of the settlement, we recognized a net tax benefit of $7 million . ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations. |
Regulatory Matters, Commitments
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
Commitments Contingencies and Guarantees [Text Block] | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million , representing the amount of the judgment, plus interest, in a case tried in 2011. On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011. FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs. Contingent Residual Support Agreement – AmeriGas In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchases. Guarantee of Collection Panhandle previously guaranteed the collections of the payment of $600 million of Regency 4.50% senior notes due 2023. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released. On April 30, 2015, in connection with the Regency Merger, ETP entered into various supplemental indentures pursuant to which ETP had agreed to fully and unconditionally guarantee all payment obligations of Regency for all of its outstanding senior notes. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released. ETP Retail Holdings Guarantee of Sunoco LP Notes In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $775 million of cash and $41 million of Sunoco LP common units. The cash portion of the consideration was financed through Sunoco LP’s issuance of $800 million principal amount of 6.375% senior notes due 2023. Retail Holdings entered into a guarantee of collection with Sunoco LP and Sunoco Finance Corp., a wholly owned subsidiary of Sunoco LP, pursuant to which Retail Holdings has agreed to provide a guarantee of collection, but not of payment, to Sunoco LP with respect to the principal amount of the senior notes issued by Sunoco LP. NGL Pipeline Regulation We have interests in NGL pipelines located in Texas and New Mexico. We commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow. Transwestern Rate Case On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to a 2011 settlement agreement with its shippers. On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015. On June 22, 2015, Transwestern filed a settlement with the FERC which resolved or provided for the resolution of all issues set for hearing in the case. On October 15, 2015, the FERC issued an order approving the rate case settlement without condition. FGT Rate Case On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective no earlier than May 1, 2015, subject to refund. On September 11, 2015, FGT filed a settlement with the FERC which resolved or provided for the resolution of all issues set for hearing in the case. On December 4, 2015, the FERC issued an order approving the rate case settlement without condition. Sea Robin Rate Case On December 2, 2013, Sea Robin filed a general NGA Section 4 rate case at the FERC as required by a previous rate case settlement. In the filing, Sea Robin sought to increase its authorized rates to recover costs related to asset retirement obligations, depreciation, and return and taxes. Filed rates were put into effect June 1, 2014 and estimated settlement rates were put into effect September 1, 2014, subject to refund. A settlement was reached with the shippers and a stipulation and agreement was filed with the FERC on July 23, 2014. The settlement was certified to the FERC by the administrative law judge on October 7, 2014 and the settlement, as modified on January 16, 2015, was approved by the FERC on June 26, 2015. In September 2015, related to the final settlement, Sea Robin made refunds to customers totaling $11 million , including interest. Commitments In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations. We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058 . 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: Years Ended December 31, 2015 2014 2013 Rental expense (1) $ 176 $ 159 $ 151 Less: Sublease rental income (16 ) (26 ) (24 ) Rental expense, net $ 160 $ 133 $ 127 (1) Includes contingent rentals totaling $26 million , $24 million and $22 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Future minimum lease commitments for such leases are: Years Ending December 31: 2016 $ 57 2017 53 2018 44 2019 39 2020 40 Thereafter 252 Future minimum lease commitments 485 Less: Sublease rental income (34 ) Net future minimum lease commitments $ 451 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. 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. MTBE Litigation Sunoco, Inc., along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs assert primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees. As of December 31, 2015 , Sunoco, Inc. is a defendant in six cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action and one case by the City of Breaux Bridge in the USDC in the Western District of Louisiana. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims. Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. In November 2015, Sunoco along with other co-defendants agreed to a global settlement in principle of the City of Breaux Bridge MTBE case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability of Sunoco, Inc. in these matters. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that 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 said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position. Regency Merger Litigation Following the January 26, 2015 announcement of the definitive merger agreement with Regency, purported Regency unitholders filed lawsuits in state and federal courts in Dallas, Texas and Delaware state court asserting claims relating to the proposed transaction. On February 3, 2015, William Engel and Enno Seago, purported Regency unitholders, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 162nd Judicial District Court of Dallas County, Texas (the “Engel Lawsuit”). The lawsuit names as defendants the Regency General Partner, the members of the Regency General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, Regency. The Engel Lawsuit alleges that (1) the Regency General Partner’s directors breached duties to Regency and the Regency’s unitholders by employing a conflicted and unfair process and failing to maximize the merger consideration; (2) the Regency General Partner’s directors breached the implied covenant of good faith and fair dealing by engaging in a flawed merger process; and (3) the non-director defendants aided and abetted in these claimed breaches. The plaintiffs seek an injunction preventing the defendants from closing the proposed transaction or an order rescinding the transaction if it has already been completed. The plaintiffs also seek money damages and court costs, including attorney’s fees. On February 9, 2015, Stuart Yeager, a purported Regency unitholder, filed a class action petition on behalf of the Regency’s common unitholders and a derivative suit on behalf of Regency in the 134th Judicial District Court of Dallas County, Texas (the “Yeager Lawsuit”). The allegations, claims, and relief sought in the Yeager Lawsuit are nearly identical to those in the Engel Lawsuit. On February 10, 2015, Lucien Coggia a purported Regency unitholder, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 192nd Judicial District Court of Dallas County, Texas (the “Coggia Lawsuit”). The allegations, claims, and relief sought in the Coggia Lawsuit are nearly identical to those in the Engel Lawsuit. On February 3, 2015, Linda Blankman, a purported Regency unitholder, filed a class action complaint on behalf of the Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Blankman Lawsuit”). The allegations and claims in the Blankman Lawsuit are similar to those in the Engel Lawsuit. However, the Blankman Lawsuit does not allege any derivative claims and includes Regency as a defendant rather than a nominal party. The lawsuit also omits one of the Regency General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the Regency General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of Regency, failing to properly value Regency, and ignoring conflicts of interest. The plaintiff also asserts a claim against the non-director defendants for aiding and abetting the directors’ alleged breach of fiduciary duty. The Blankman Lawsuit seeks the same relief that the plaintiffs seek in the Engel Lawsuit. On February 6, 2015, Edwin Bazini, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Bazini Lawsuit”). The allegations, claims, and relief sought in the Bazini Lawsuit are nearly identical to those in the Blankman Lawsuit. On March 27, 2015, Plaintiff Bazini filed an amended complaint asserting additional claims under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934. On February 11, 2015, Mark Hinnau, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Hinnau Lawsuit”). The allegations, claims, and relief sought in the Hinnau Lawsuit are nearly identical to those in the Blankman Lawsuit. On February 11, 2015, Stephen Weaver, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Weaver Lawsuit”). The allegations, claims, and relief sought in the Weaver Lawsuit are nearly identical to those in the Blankman Lawsuit. On February 11, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Dieckman Lawsuit are similar to those in the Blankman Lawsuit, except that the Dieckman Lawsuit does not assert an aiding and abetting claim. On February 13, 2015, Irwin Berlin, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Berlin Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit. On March 13, 2015, the Court in the 95th Judicial District Court of Dallas County, Texas transferred and consolidated the Yeager and Coggia Lawsuits into the Engel Lawsuit and captioned the consolidated lawsuit as Engel v. Regency GP, LP, et al. (the “Consolidated State Lawsuit”). On March 30, 2015, Leonard Cooperman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Cooperman Lawsuit”). The allegations, claims, and relief sought in the Cooperman Lawsuit are similar to those in the Blankman Lawsuit. On March 31, 2015, the Court in United States District Court for the Northern District of Texas consolidated the Blankman, Bazini, Hinnau, Weaver, Dieckman, and Berlin Lawsuits into a consolidated lawsuit captioned Bazini v. Bradley, et al. (the “Consolidated Federal Lawsuit”). On April 1, 2015, plaintiffs in the Consolidated Federal Lawsuit filed an Emergency Motion to Expedite Discovery. On April 9, 2015, by order of the Court, the parties submitted a joint submission wherein defendants opposed plaintiffs’ request to expedite discovery. On April 17, 2015, the Court denied plaintiffs’ motion to expedite discovery. On June 10, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware (the “Dieckman DE Lawsuit”). The lawsuit alleges that the transaction did not comply with the Regency partnership agreement because the Conflicts Committee was not properly formed. On July 6, 2015, Defendants filed Motions to Dismiss and the briefing has since been completed. Oral argument on the Motions was held in December 2015. On September 29, 2015, Chancellor Bouchard ordered discovery stayed, pending a ruling on Defendants’ Motions to Dismiss. On June 5, 2015, the Dieckman Lawsuit was dismissed. On July 23, 2015, the Blankman, Bazini, Hinnau, Weaver and Berlin Lawsuits were dismissed. On August 20, 2015, the Cooperman Lawsuit was dismissed. The Consolidated Federal Lawsuit was terminated once all named plaintiffs voluntarily dismissed. On January 8, 2016, the plaintiffs in the Consolidated State Lawsuit filed a notice of non-suit without prejudice. The Dieckman DE Lawsuit is the only lawsuit that remains. The Defendants cannot predict the outcome of this lawsuit, or the amount of time and expense that will be required to resolve it. The Defendants intend to vigorously defend the lawsuit. 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 has filed a notice of appeal with the Texas Court of Appeals, and briefing by Enterprise and ETP is complete. Oral argument has not been scheduled. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed. 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 December 31, 2015 and 2014 , accruals of approximately $40 million and $37 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. No amounts have been recorded in our December 31, 2015 or 2014 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Attorney General of the Commonwealth of Massachusetts v. New England Gas Company On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling approximately $19 million , that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50% , level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses. Compliance Orders from the New Mexico Environmental Department Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses. Lone Star NGL Fractionators Notice of Enforcement Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to Mont Belvieu Gas Plant. The Partnership has accrued $300,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses. 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. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. 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. Environmental Remediation Our subsidiaries are responsible for environmental remediation at certain sites, including the following: • Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. • Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. • Currently operating Sunoco, Inc. retail sites. • Legacy sites related to Sunoco, Inc., that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites. • Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2015 , Sunoco, Inc. had been named as a PRP at approximately 50 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. 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. December 31, 2015 2014 Current $ 41 $ 41 Non-current 326 360 Total environmental liabilities $ 367 $ 401 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 years ended December 31, 2015 and 2014 , the Partnership had $38 million and $48 million , respectively, of expenditures related to environmental cleanup 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, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an 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 |
Derivative assets and liabiltie
Derivative assets and liabilties (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |
DERIVATIVE ASSETS AND LIABILITIES | DERIVATIVE 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 use derivatives in our liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. Sunoco Logistics utilizes swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These contracts are not designated as hedges for accounting purposes. We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing segment. 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: December 31, 2015 December 31, 2014 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (602,500 ) 2016-2017 (232,500 ) 2015 Basis Swaps IFERC/NYMEX (1) (31,240,000 ) 2016-2017 (13,907,500 ) 2015-2016 Options – Calls — — 5,000,000 2015 Power (Megawatt): Forwards 357,092 2016-2017 288,775 2015 Futures (109,791 ) 2016 (156,000 ) 2015 Options – Puts 260,534 2016 (72,000 ) 2015 Options – Calls 1,300,647 2016 198,556 2015 Crude (Bbls) – Futures (591,000 ) 2016-2017 — — (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (6,522,500 ) 2016-2017 57,500 2015 Swing Swaps IFERC 71,340,000 2016-2017 46,150,000 2015 Fixed Swaps/Futures (14,380,000 ) 2016-2018 (34,304,000 ) 2015-2016 Forward Physical Contracts 21,922,484 2016-2017 (9,116,777 ) 2015 Natural Gas Liquid (Bbls) – Forwards/Swaps (8,146,800 ) 2016-2018 (4,417,400 ) 2015 Refined Products (Bbls) – Futures (993,000 ) 2016-2017 13,745,755 2015 Corn (Bushels) – Futures 1,185,000 2016 — — Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (37,555,000 ) 2016 (39,287,500 ) 2015 Fixed Swaps/Futures (37,555,000 ) 2016 (39,287,500 ) 2015 Hedged Item – Inventory 37,555,000 2016 39,287,500 2015 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. 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 manage interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances. The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding December 31, 2015 December 31, 2014 July 2015 (2) Forward-starting to pay a fixed rate of 3.38% and receive a floating rate $ — $ 200 July 2016 (3) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 200 200 July 2017 (4) Forward-starting to pay a fixed rate of 3.84% and receive a floating rate 300 300 July 2018 (4) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 200 July 2019 (4) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 300 December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 — March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 — February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% — 200 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have terms of 10 years with a mandatory termination date the same as the effective date. (3) Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date. (4) Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. 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: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives December 31, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 38 $ 43 $ (3 ) $ — 38 43 (3 ) — Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 353 617 (306 ) (577 ) Commodity derivatives 57 107 (41 ) (23 ) Interest rate derivatives — 3 (171 ) (155 ) Embedded derivatives in ETP Preferred Units — — (5 ) (16 ) 410 727 (523 ) (771 ) Total derivatives $ 448 $ 770 $ (526 ) $ (771 ) 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: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives without offsetting agreements Derivative assets (liabilities) $ — $ 3 $ (176 ) $ (171 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 57 107 (41 ) (23 ) Broker cleared derivative contracts Other current assets 391 660 (309 ) (577 ) 448 770 (526 ) (771 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (17 ) (19 ) 17 19 Payments on margin deposit Other current assets (309 ) (577 ) 309 577 Total net derivatives $ 122 $ 174 $ (200 ) $ (175 ) 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 with respect to our derivative financial instruments: Change in Value Recognized in OCI on Derivatives (Effective Portion) Years Ended December 31, 2015 2014 2013 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ — $ (1 ) Total $ — $ — $ (1 ) Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Years Ended December 31, 2015 2014 2013 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ (3 ) $ 4 Total $ — $ (3 ) $ 4 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2015 2014 2013 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 21 $ (8 ) $ 8 Total $ 21 $ (8 ) $ 8 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2015 2014 2013 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (11 ) $ (6 ) $ (11 ) Commodity derivatives – Non-trading Cost of products sold 23 199 (21 ) Commodity contracts – Non-trading Deferred gas purchases — — (3 ) Interest rate derivatives Gains (losses) on interest rate derivatives (18 ) (157 ) 44 Embedded derivatives Other, net 12 3 6 Total $ 6 $ 39 $ 15 |
Retirement Benefits (Notes)
Retirement Benefits (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
RETIREMENT BENEFITS | |
Pension and Other Postretirement Benefits Disclosure | RETIREMENT BENEFITS: Savings and Profit Sharing Plans We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $39 million , $50 million and $45 million to these 401(k) savings plans for the years ended December 31, 2015, 2014, and 2013 , respectively. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 2015 and 2014 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees. Sunoco, Inc. Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015. Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations. Obligations and Funded Status Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2015 December 31, 2014 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 718 $ 65 $ 202 $ 632 $ 61 $ 223 Interest cost 23 2 4 28 3 5 Amendments — — — — — 1 Benefits paid, net (46 ) (8 ) (20 ) (45 ) (9 ) (28 ) Actuarial (gain) loss and other 16 (2 ) (6 ) 130 10 2 Settlements (691 ) — — (27 ) — — Dispositions — — — — — (1 ) Benefit obligation at end of period 20 57 180 718 65 202 Change in plan assets: Fair value of plan assets at beginning of period 598 — 265 600 — 284 Return on plan assets and other 16 — — 70 — 6 Employer contributions 138 — 8 — — 8 Benefits paid, net (46 ) — (20 ) (45 ) — (28 ) Settlements (691 ) — — (27 ) — — Dispositions — — — — — (5 ) Fair value of plan assets at end of period 15 — 253 598 — 265 Amount underfunded (overfunded) at end of period $ 5 $ 57 $ (73 ) $ 120 $ 65 $ (63 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 97 $ — $ — $ 90 Current liabilities — (9 ) (2 ) — (9 ) (2 ) Non-current liabilities (5 ) (48 ) (22 ) (120 ) (56 ) (25 ) $ (5 ) $ (57 ) $ 73 $ (120 ) $ (65 ) $ 63 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain $ 2 $ 4 $ (17 ) $ 18 $ 7 $ (20 ) Prior service cost — — 15 — — 17 $ 2 $ 4 $ (2 ) $ 18 $ 7 $ (3 ) The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2015 December 31, 2014 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 20 $ 57 N/A $ 718 $ 65 N/A Accumulated benefit obligation 20 57 $ 180 718 65 $ 202 Fair value of plan assets 15 — 253 598 — 265 Components of Net Periodic Benefit Cost December 31, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Interest cost $ 25 $ 4 $ 31 $ 5 Expected return on plan assets (16 ) (8 ) (40 ) (8 ) Prior service cost amortization — 1 — 1 Actuarial loss amortization — — (1 ) (1 ) Settlements 32 — (4 ) — Net periodic benefit cost $ 41 $ (3 ) $ (14 ) $ (3 ) Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.59 % 2.38 % 3.62 % 2.24 % Rate of compensation increase N/A N/A N/A N/A The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.65 % 2.79 % 4.65 % 3.02 % Expected return on assets: Tax exempt accounts 7.50 % 7.00 % 7.50 % 7.00 % Taxable accounts N/A 4.50 % N/A 4.50 % Rate of compensation increase N/A N/A N/A N/A The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness. The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: December 31, 2015 2014 Health care cost trend rate 7.16 % 7.09 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.39 % 5.41 % Year that the rate reaches the ultimate trend rate 2018 2018 Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits. Plan Assets For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35% , fixed income of 65% to 75% and cash and cash equivalents of up to 10% . The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets. The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2015 Using Fair Value Hierarchy Fair Value as of December 31, 2015 Level 1 Level 2 Level 3 Asset category: Mutual funds (1) $ 15 — 15 — Total $ 15 $ — $ 15 $ — (1) Comprised of approximately 100% equities as of December 31, 2015 . Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 25 $ 25 $ — $ — Mutual funds (1) 110 — 110 — Fixed income securities 463 — 463 — Total $ 598 $ 25 $ 573 $ — (1) Comprised of approximately 100% equities as of December 31, 2014 . The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2015 Using Fair Value Hierarchy Fair Value as of December 31, 2015 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 133 133 — — Fixed income securities 102 — 102 — Total $ 253 $ 151 $ 102 $ — (1) Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015 . Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 9 $ 9 $ — $ — Mutual funds (1) 131 131 — — Fixed income securities 125 — 125 — Total $ 265 $ 140 $ 125 $ — (1) Primarily comprised of approximately 56% equities, 38% fixed income securities and 6% cash as of December 31, 2014 . The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. Contributions We expect to contribute $16 million to pension plans and $10 million to other postretirement plans in 2016 . The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes. Benefit Payments Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Pension Benefits Years Funded Plans Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2016 $ 20 $ 9 $ 21 2017 — 7 20 2018 — 7 19 2019 — 6 17 2020 — 6 16 2021 – 2025 — 2 58 The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Panhandle does not expect to receive any Medicare Part D subsidies in any future periods. |
Related Party Transactions (Not
Related Party Transactions (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS: ETE has agreements with subsidiaries to provide or receive various general and administrative services. ETE pays us to provide services on its behalf and on behalf of other subsidiaries of ETE, which includes the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries. In connection with the Lake Charles LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. In January 2016, ETE and ETP agreed to extend the $95 million annual management fee paid to ETP through 2016. The Partnership also 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: Years Ended December 31, 2015 2014 2013 Affiliated revenues $ 417 $ 965 $ 1,442 The following table summarizes the related company balances on our consolidated balance sheets: December 31, 2015 2014 Accounts receivable from related companies: Sunoco LP $ 3 $ — ETE 110 11 PES 10 6 FGT 13 9 Lake Charles LNG 36 3 Trans-Pecos Pipeline, LLC 29 — Comanche Trail Pipeline, LLC 22 — Other 45 110 Total accounts receivable from related companies $ 268 $ 139 Accounts payable to related companies: Sunoco LP $ 5 $ — FGT 1 2 Lake Charles LNG 3 2 Other 16 21 Total accounts payable to related companies $ 25 $ 25 |
Reportable Segments (Notes)
Reportable Segments (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
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; • liquids transportation and services; • investment in Sunoco Logistics; • retail marketing; and • all other. Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. 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 liquids transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in Sunoco Logistics segment are primarily reflected in crude sales. Revenues from our retail marketing segment are primarily reflected in refined product sales. In connection with the Regency Merger, Regency’s operations were aggregated into ETP’s existing segments. Regency’s gathering and processing operations were aggregated into our midstream segment. Regency’s natural gas transportation operations were aggregated into our intrastate transportation and storage and interstate transportation and storage segments. Regency’s contract services and natural resources operations were aggregated into our all other segment. Additionally, in June 2015, Regency’s 30% equity interest in Lone Star was transferred to ETC OLP. 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, loss on extinguishment of debt, gain on deconsolidation 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 (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership. The following tables present financial information by segment: Years Ended December 31, 2015 2014 2013 Revenues: Intrastate transportation and storage: Revenues from external customers $ 1,912 $ 2,645 $ 2,242 Intersegment revenues 338 212 210 2,250 2,857 2,452 Interstate transportation and storage: Revenues from external customers 1,008 1,057 1,270 Intersegment revenues 17 15 39 1,025 1,072 1,309 Midstream: Revenues from external customers 2,622 4,770 3,220 Intersegment revenues 2,449 2,053 1,056 5,071 6,823 4,276 Liquids transportation and services: Revenues from external customers 3,232 3,730 2,025 Intersegment revenues 249 181 101 3,481 3,911 2,126 Investment in Sunoco Logistics: Revenues from external customers 10,302 17,920 16,480 Intersegment revenues 184 168 159 10,486 18,088 16,639 Retail marketing: Revenues from external customers 12,478 22,484 21,004 Intersegment revenues 4 3 8 12,482 22,487 21,012 All other: Revenues from external customers 2,738 2,869 2,094 Intersegment revenues 554 462 503 3,292 3,331 2,597 Eliminations (3,795 ) (3,094 ) (2,076 ) Total revenues $ 34,292 $ 55,475 $ 48,335 Years Ended December 31, 2015 2014 2013 Cost of products sold: Intrastate transportation and storage $ 1,554 $ 2,169 $ 1,737 Midstream 3,266 4,893 3,130 Liquids transportation and services 2,595 3,166 1,654 Investment in Sunoco Logistics 9,307 17,135 15,600 Retail marketing 11,174 21,154 20,150 All other 2,855 2,975 2,337 Eliminations (3,722 ) (3,078 ) (2,028 ) Total cost of products sold $ 27,029 $ 48,414 $ 42,580 Years Ended December 31, 2015 2014 2013 Depreciation, depletion and amortization: Intrastate transportation and storage $ 129 $ 125 $ 122 Interstate transportation and storage 210 203 244 Midstream 720 569 335 Liquids transportation and services 126 113 91 Investment in Sunoco Logistics 382 296 265 Retail marketing 190 189 114 All other 172 174 125 Total depreciation, depletion and amortization $ 1,929 $ 1,669 $ 1,296 Years Ended December 31, 2015 2014 2013 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 32 $ 27 $ 30 Interstate transportation and storage 197 196 182 Midstream (19 ) 10 1 Liquids transportation and services (2 ) (3 ) (2 ) Investment in Sunoco Logistics 21 23 18 Retail marketing 194 2 2 All other 46 77 5 Total equity in earnings of unconsolidated affiliates $ 469 $ 332 $ 236 Years Ended December 31, 2015 2014 2013 Segment Adjusted EBITDA: Intrastate transportation and storage $ 543 $ 559 $ 521 Interstate transportation and storage 1,155 1,212 1,368 Midstream 1,250 1,318 757 Liquids transportation and services 731 591 350 Investment in Sunoco Logistics 1,153 971 871 Retail marketing 583 731 325 All other 299 328 212 Total Segment Adjusted EBITDA 5,714 5,710 4,404 Depreciation, depletion and amortization (1,929 ) (1,669 ) (1,296 ) Interest expense, net of interest capitalized (1,291 ) (1,165 ) (1,013 ) Gain on sale of AmeriGas common units — 177 87 Impairment losses (339 ) (370 ) (689 ) Gains (losses) on interest rate derivatives (18 ) (157 ) 44 Non-cash unit-based compensation expense (79 ) (68 ) (54 ) Unrealized gains (losses) on commodity risk management activities (65 ) 112 42 Inventory valuation adjustments (104 ) (473 ) 3 Losses on extinguishments of debt (43 ) (25 ) (7 ) Non-operating environmental remediation — — (168 ) Adjusted EBITDA related to discontinued operations — (27 ) (76 ) Adjusted EBITDA related to unconsolidated affiliates (937 ) (748 ) (722 ) Equity in earnings of unconsolidated affiliates 469 332 236 Other, net 20 (36 ) 19 Income from continuing operations before income tax expense $ 1,398 $ 1,593 $ 810 December 31, 2015 2014 2013 Assets: Intrastate transportation and storage $ 4,882 $ 4,983 $ 5,048 Interstate transportation and storage 11,345 10,779 11,537 Midstream 17,111 15,562 7,847 Liquids transportation and services 7,235 4,568 4,321 Investment in Sunoco Logistics 15,423 13,619 11,650 Retail marketing 3,218 8,917 3,936 All other 5,959 4,090 5,561 Total assets $ 65,173 $ 62,518 $ 49,900 Years Ended December 31, 2015 2014 2013 Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis): Intrastate transportation and storage $ 105 $ 169 $ 47 Interstate transportation and storage 860 411 152 Midstream 2,172 1,298 1,114 Liquids transportation and services 2,109 427 448 Investment in Sunoco Logistics 2,126 2,510 1,018 Retail marketing 412 259 176 All other 383 420 372 Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) $ 8,167 $ 5,494 $ 3,327 December 31, 2015 2014 2013 Advances to and investments in unconsolidated affiliates: Intrastate transportation and storage $ 406 $ 423 $ 443 Interstate transportation and storage 2,516 2,649 2,588 Midstream 117 138 36 Liquids transportation and services 32 31 29 Investment in Sunoco Logistics 247 226 125 Retail marketing 1,541 19 22 All other 144 274 807 Total advances to and investments in unconsolidated affiliates $ 5,003 $ 3,760 $ 4,050 |
Quarterly Financial Data (Notes
Quarterly Financial Data (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Data [Abstract] | |
QUARTERLY FINANCIAL DATA (UNAUDITED) | QUARTERLY FINANCIAL DATA (UNAUDITED): Summarized unaudited quarterly financial data is presented below. The sum of net income per Limited Partner unit by quarter does not equal the net income per limited partner unit for the year due to the computation of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts. Quarters Ended March 31 June 30 September 30 December 31 Total Year 2015: Revenues $ 10,326 $ 11,540 $ 6,601 $ 5,825 $ 34,292 Operating income 608 888 576 187 2,259 Net income 268 839 393 21 1,521 Common Unitholders’ interest in net income (loss) (48 ) 298 59 (327 ) (18 ) Basic net income (loss) per Common Unit $ (0.17 ) $ 0.67 $ 0.11 $ (0.68 ) $ (0.09 ) Diluted net income (loss) per Common Unit $ (0.17 ) $ 0.67 $ 0.10 $ (0.68 ) $ (0.10 ) Quarters Ended March 31 June 30 September 30 December 31 Total Year 2014: Revenues $ 13,027 $ 14,088 $ 14,933 $ 13,427 $ 55,475 Operating income 706 769 809 159 2,443 Net income (loss) 483 548 513 (245 ) 1,299 Common Unitholders’ interest in net income (loss) 253 295 148 (90 ) 606 Basic net income (loss) per Common Unit $ 0.76 $ 0.92 $ 0.44 $ (0.28 ) $ 1.77 Diluted net income (loss) per Common Unit $ 0.76 $ 0.92 $ 0.44 $ (0.28 ) $ 1.77 The three months ended December 31, 2015 and 2014 reflected the unfavorable impacts of $120 million and $456 million , respectively, related to non-cash inventory valuation adjustments primarily in our investment in Sunoco Logistics and retail marketing segments. The three months ended December 31, 2015 and 2014 reflected the recognition of impairment losses of $339 million and $370 million , respectively. Impairment losses in 2015 were primarily related to our Lone Star Refinery Services operations and our Transwestern pipeline, and in 2014 , impairment losses were primarily related to Regency’s Permian Basin gathering and processing operations. For the three months ended December 31, 2015 and 2014 , distributions paid for the period exceeded net income attributable to partners by $934 million and $544 million , respectively. Accordingly, the distributions paid to 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. |
Estimates, Significant Accoun24
Estimates, Significant Accounting Policies and Balance Sheet Detials (Policy) | 12 Months Ended |
Dec. 31, 2015 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Pronouncements 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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies. In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidation analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption was permitted. We expect to adopt this standard for the year ended December 31, 2016, and we do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which simplifies the presentation of debt issuance costs by requiring debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. ASU 2015-03 is effective for annual reporting periods after December 15, 2015, including interim periods within that reporting period, with early adoption permitted for financial statements that have not been previously issued. Upon adoption, ASU 2015-03 must be applied retrospectively to all prior reporting period presented. We adopted and applied this standard to all consolidated financial statements presented and there was not a material impact to our financial position or results of operations as a result of the adoption of this standard. In August 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805) - Simplifying the Accounting for Measurement-Period Adjustments. This update requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Additionally, this update requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Finally, this update requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in this update are effective for financial statements issued with fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance and prior period amounts have been reclassified to conform to the current period presentation. As a result of the early adoption and retrospective application of ASU 2015-17, $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements. |
Revenue Recognition | Revenue Recognition Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Our intrastate transportation and storage and interstate transportation and storage segments’ results 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. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues. Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we 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, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer. In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations. Our retail marketing segment sells gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease with the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured. |
Regulatory Accounting - Regulatory Assets and Liabilities | Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs. |
Cash, Cash Equivalents and Supplemental Cash Flow Information | Cash, Cash Equivalents and Supplemental Cash Flow Information 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. |
Accounts Receivable | Accounts Receivable Our midstream, NGL and intrastate transportation and storage operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned for all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. Master setoff agreements are put in place with counterparties where appropriate to mitigate risk. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Based on that review, a letter of credit or other security may be required. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted. We have a concentration of customers in the electric and gas utility industries as well as oil and natural gas producers and municipalities. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness based upon pre-established standards consistent with FERC filed tariffs to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due. Our retail marketing segment extends credit to customers after a review of various credit indicators. Depending on the type of customer and its risk profile, security in the form of a cash deposit, letter of credit or mortgages may be required. Management records reserves for bad debt by computing a proportion of average write-off activity over the past five years in comparison to the outstanding balance in accounts receivable. This proportion is then applied to the accounts receivable balance at the end of the reporting period to calculate a current estimate of what is uncollectible. The allowance computation may then be adjusted to reflect input provided by the credit department and business line managers who may have specific knowledge of uncollectible items. The credit department and business line managers make the decision to write off an account, based on understanding of the potential collectability. We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets. |
Inventories | Inventories Inventories consist principally of natural gas held in storage, crude oil, refined products and spare parts. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method. Inventories consisted of the following: December 31, 2015 2014 Natural gas and NGLs $ 415 $ 392 Crude oil 424 364 Refined products 104 392 Spare parts and other 270 312 Total inventories $ 1,213 $ 1,460 During the year ended December 31, 2015 , the Partnership recorded write-downs of $104 million on its crude oil, refined products and NGL inventories as a result of a decline in the market price of these products. The write-down was calculated based upon current replacement costs. 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. |
Exchanges | Exchanges Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average cost pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms. |
Other Current Assets | Other Current Assets Other current assets consisted of the following: December 31, 2015 2014 Deposits paid to vendors $ 74 $ 65 Income taxes receivable 291 17 Prepaid expenses and other 137 200 Total other current assets $ 502 $ 282 |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the liquids transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds. Components and useful lives of property, plant and equipment were as follows: December 31, 2015 2014 Land and improvements $ 686 $ 1,307 Buildings and improvements (1 to 45 years) 1,526 1,918 Pipelines and equipment (5 to 83 years) 33,148 27,164 Natural gas and NGL storage facilities (5 to 46 years) 391 1,215 Bulk storage, equipment and facilities (2 to 83 years) 2,853 2,583 Tanks and other equipment (5 to 40 years) 60 58 Retail equipment (2 to 99 years) 401 515 Vehicles (1 to 25 years) 220 203 Right of way (20 to 83 years) 2,573 2,445 Furniture and fixtures (2 to 25 years) 55 57 Linepack 61 119 Pad gas 44 44 Natural resources 484 454 Other (1 to 30 years) 523 979 Construction work-in-process 7,844 4,343 50,869 43,404 Less – Accumulated depreciation and depletion (5,782 ) (4,497 ) Property, plant and equipment, net $ 45,087 $ 38,907 We recognized the following amounts for the periods presented: Years Ended December 31, 2015 2014 2013 Depreciation and depletion expense $ 1,713 $ 1,457 $ 1,202 Capitalized interest, excluding AFUDC $ 163 $ 101 $ 45 |
Advances to and Investment in Affiliates | Advances to and Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. |
Other Noncurrent Assets [Policy Text Block] | Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2015 2014 Unamortized financing costs (1) $ 11 $ 30 Regulatory assets 90 85 Deferred charges 198 220 Restricted funds 192 177 Other 45 132 Total other non-current assets, net $ 536 $ 644 (1) Includes unamortized financing costs related to the Partnership’s revolving credit facilities. Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies. |
Intangible Assets Disclosure [Text Block] | Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 2015 December 31, 2014 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 4,601 $ (554 ) $ 5,067 $ (464 ) Patents (9 years) 48 (16 ) 48 (11 ) Trade Names (15 years) 66 (18 ) 556 (15 ) Other (1 to 15 years) 6 (3 ) 36 (7 ) Total amortizable intangible assets $ 4,721 $ (591 ) $ 5,707 $ (497 ) Non-amortizable intangible assets: Trademarks 291 — 316 — Total intangible assets $ 5,012 $ (591 ) $ 6,023 $ (497 ) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2015 2014 2013 Reported in depreciation, depletion and amortization $ 216 $ 212 $ 117 Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2016 $ 195 2017 195 2018 195 2019 193 2020 193 We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. In 2015, we recorded $24 million of intangible asset impairments related to the liquids transportation and services segment primarily due to an expected decrease in future cash flows. |
Goodwill | Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream Liquids Transportation and Services Investment in Sunoco Logistics Retail Marketing All Other Total Balance, December 31, 2013 $ 10 $ 1,195 $ 686 $ 432 $ 1,346 $ 1,445 $ 742 $ 5,856 Acquired — — 451 — 12 1,862 15 2,340 Disposed — (184 ) — — — — — (184 ) Impaired — — (370 ) — — — — (370 ) Balance, December 31, 2014 10 1,011 767 432 1,358 3,307 757 7,642 Reduction due to Sunoco LP deconsolidation — — — — — (2,018 ) — (2,018 ) Impaired — (99 ) — (106 ) — — (205 ) Other — — (49 ) — — — 58 9 Balance, December 31, 2015 $ 10 $ 912 $ 718 $ 326 $ 1,358 $ 1,289 $ 815 $ 5,428 Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. We recorded a net decrease in goodwill of $2.21 billion during the year ended December 31, 2015 , primarily due the deconsolidation of Sunoco LP of $2.02 billion subsequent to ETE’s acquisition in 2015 (see Note 3 ). During 2015, the Partnership voluntarily changed the date of the annual goodwill impairment testing to the first day of the fourth quarter. The Partnership believes this new date is preferable because it allows for more timely completion of the annual goodwill impairment test prior to the end of the annual financial reporting period. This change in accounting principle does not delay, accelerate or avoid any potential impairment loss, nor does the change have a cumulative effect on income from continuing operations, net income or loss, or net assets. This change was not applied retrospectively, as doing so would require the use of significant estimates and assumptions that include hindsight. Accordingly, the Partnership applied the change in annual goodwill impairment testing date prospectively beginning October 1, 2015. During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of: (i) $99 million in the Transwestern reporting unit due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015 and (ii) $106 million in the Lone Star Refinery Services reporting unit due primarily to changes in assumptions related to potential future revenues decrease as well as the market declines in current and expected future commodity prices. During the fourth quarter of 2014, a $370 million goodwill impairment was recorded related to Regency’s Permian Basin gathering and processing operations. The decline in estimated fair value of that reporting unit was primarily driven by the significant decline in commodity prices in the fourth quarter of 2014, and the resulting impact to future commodity prices, as well as, increases in future estimated operations and maintenance expenses. The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. |
Asset Retirement Obligation | Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates. Except for certain amounts recorded by Panhandle, Sunoco Logistics and our retail marketing operations, discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2015 and 2014 , in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time. Below is a schedule of AROs by segment recorded as other non-current liabilities in ETP’s consolidated balance sheets: December 31, 2015 2014 Interstate transportation and storage $ 58 $ 60 Investment in Sunoco Logistics 88 41 Retail marketing 66 87 $ 212 $ 188 Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. Long-lived assets related to AROs aggregated $18 million and were reflected as property, plant and equipment on our balance sheet as of December 31, 2015 and 2014 . In addition, the Partnership had $6 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2015 . |
Accrued and Other Current Liabilities | Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: December 31, 2015 2014 Interest payable $ 425 $ 382 Customer advances and deposits 95 103 Accrued capital expenditures 743 673 Accrued wages and benefits 218 233 Taxes payable other than income taxes 76 236 Other 386 373 Total accrued and other current liabilities $ 1,943 $ 2,000 Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit. |
Redeemable Noncontrolling Interest [Text Block] | Redeemable Noncontrolling Interests The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheet. |
Environmental Costs, Policy [Policy Text Block] | Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued. |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. 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 debt obligations as of December 31, 2015 was $25.71 billion and $28.68 billion , respectively. As of December 31, 2014 , the aggregate fair value and carrying amount of our debt obligations was $26.91 billion and $25.84 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, interest rate derivatives and embedded derivatives in our preferred units 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. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the year ended December 31, 2015 , no transfers were made between any levels within the fair value hierarchy. |
Contributions in Aid of Construction Costs | Contributions in Aid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized. |
Shipping and Handling Costs | Shipping and Handling Costs Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses. |
Costs and Expenses | Costs and Expenses Costs of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel. We record the collection of taxes to be remitted to government authorities on a net basis except for our retail marketing segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by our retail marketing segment were $1.85 billion , $2.46 billion and $2.22 billion for the years ended December 31, 2015 , 2014 and 2013 , respectively. |
Consolidation, Subsidiary Stock Issuances, Policy [Policy Text Block] | Issuances of Subsidiary Units We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital. |
Income Tax, Policy [Policy Text Block] | Income Taxes ETP is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2015, 2014, and 2013 , our qualifying income met the statutory requirement. The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Oasis Pipeline Company and until July 31, 2015, Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes. |
Accounting for Derivative Instruments and Hedging Activities | Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations. |
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block] | Unit-Based Compensation For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets. |
Pension and Other Postretirement Plans, Policy [Policy Text Block] | Pensions and Other Postretirement Benefit Plans Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability. |
Allocation of Income (Loss) | Allocation of Income For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests. |
Estimates, Significant Accoun25
Estimates, Significant Accounting Policies and Balance Sheet Detials (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |
Net change in operating assets and liabilities (net of acquisitions) | 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: Years Ended December 31, 2015 2014 2013 Accounts receivable $ 819 $ 600 $ (557 ) Accounts receivable from related companies (243 ) (22 ) 26 Inventories (351 ) 51 (254 ) Exchanges receivable 13 18 (8 ) Other current assets (191 ) 132 (58 ) Other non-current assets, net 188 (6 ) (45 ) Accounts payable (1,215 ) (851 ) 542 Accounts payable to related companies (160 ) 3 (143 ) Exchanges payable (78 ) (99 ) 128 Accrued and other current liabilities (5 ) (92 ) 211 Other non-current liabilities (219 ) (73 ) 147 Price risk management assets and liabilities, net 75 19 (147 ) Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (1,367 ) $ (320 ) $ (158 ) |
Non-cash investing and financing activities and supplemental cash flow information | Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2015 2014 2013 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 896 $ 643 $ 226 Net gains from subsidiary common unit transactions 300 175 — NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the Regency Merger $ 9,250 $ — $ — Issuance of Class H Units in connection with the Bakken Pipeline Transaction 1,946 — — Issuance of Common Units in connection with the Susser Merger — 908 — Issuance of Common Units in connection with the ETP Holdco Acquisition — — 2,464 Issuance of Class H Units — — 1,514 Contribution of property, plant and equipment from noncontrolling interest 34 — — Long-term debt assumed and non-compete agreement notes payable issued in acquisitions — 564 — Predecessor equity issuances of common units in connection with Regency’s acquisitions — 4,281 — Long-term debt assumed or exchanged in Regency’s acquisitions — 2,386 — Redemption of Common Units in connection with the Bakken Pipeline Transaction 999 — — Redemption of Common Units in connection with the Sunoco LP Exchange 52 — — Redemption of Common Units in connection with the Lake Charles LNG Transaction — 1,167 — SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,467 $ 1,232 $ 1,049 Cash paid for income taxes 71 344 58 |
Inventory | Inventories consisted of the following: December 31, 2015 2014 Natural gas and NGLs $ 415 $ 392 Crude oil 424 364 Refined products 104 392 Spare parts and other 270 312 Total inventories $ 1,213 $ 1,460 |
Other Current Assets | Other current assets consisted of the following: December 31, 2015 2014 Deposits paid to vendors $ 74 $ 65 Income taxes receivable 291 17 Prepaid expenses and other 137 200 Total other current assets $ 502 $ 282 |
Components and useful lives of property, plant and equipment | Components and useful lives of property, plant and equipment were as follows: December 31, 2015 2014 Land and improvements $ 686 $ 1,307 Buildings and improvements (1 to 45 years) 1,526 1,918 Pipelines and equipment (5 to 83 years) 33,148 27,164 Natural gas and NGL storage facilities (5 to 46 years) 391 1,215 Bulk storage, equipment and facilities (2 to 83 years) 2,853 2,583 Tanks and other equipment (5 to 40 years) 60 58 Retail equipment (2 to 99 years) 401 515 Vehicles (1 to 25 years) 220 203 Right of way (20 to 83 years) 2,573 2,445 Furniture and fixtures (2 to 25 years) 55 57 Linepack 61 119 Pad gas 44 44 Natural resources 484 454 Other (1 to 30 years) 523 979 Construction work-in-process 7,844 4,343 50,869 43,404 Less – Accumulated depreciation and depletion (5,782 ) (4,497 ) Property, plant and equipment, net $ 45,087 $ 38,907 |
Depreciation expense | We recognized the following amounts for the periods presented: Years Ended December 31, 2015 2014 2013 Depreciation and depletion expense $ 1,713 $ 1,457 $ 1,202 Capitalized interest, excluding AFUDC $ 163 $ 101 $ 45 |
Other non-current assets | Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2015 2014 Unamortized financing costs (1) $ 11 $ 30 Regulatory assets 90 85 Deferred charges 198 220 Restricted funds 192 177 Other 45 132 Total other non-current assets, net $ 536 $ 644 (1) Includes unamortized financing costs related to the Partnership’s revolving credit facilities. |
Components and useful lives of intangibles assets | Components and useful lives of intangible assets were as follows: December 31, 2015 December 31, 2014 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 4,601 $ (554 ) $ 5,067 $ (464 ) Patents (9 years) 48 (16 ) 48 (11 ) Trade Names (15 years) 66 (18 ) 556 (15 ) Other (1 to 15 years) 6 (3 ) 36 (7 ) Total amortizable intangible assets $ 4,721 $ (591 ) $ 5,707 $ (497 ) Non-amortizable intangible assets: Trademarks 291 — 316 — Total intangible assets $ 5,012 $ (591 ) $ 6,023 $ (497 ) |
Amortization expense of intangible assets | Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2015 2014 2013 Reported in depreciation, depletion and amortization $ 216 $ 212 $ 117 |
Amortization expense, expected | Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2016 $ 195 2017 195 2018 195 2019 193 2020 193 |
Changes in carrying amount of goodwill | Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream Liquids Transportation and Services Investment in Sunoco Logistics Retail Marketing All Other Total Balance, December 31, 2013 $ 10 $ 1,195 $ 686 $ 432 $ 1,346 $ 1,445 $ 742 $ 5,856 Acquired — — 451 — 12 1,862 15 2,340 Disposed — (184 ) — — — — — (184 ) Impaired — — (370 ) — — — — (370 ) Balance, December 31, 2014 10 1,011 767 432 1,358 3,307 757 7,642 Reduction due to Sunoco LP deconsolidation — — — — — (2,018 ) — (2,018 ) Impaired — (99 ) — (106 ) — — (205 ) Other — — (49 ) — — — 58 9 Balance, December 31, 2015 $ 10 $ 912 $ 718 $ 326 $ 1,358 $ 1,289 $ 815 $ 5,428 |
Schedule of Asset Retirement Obligations [Table Text Block] | Below is a schedule of AROs by segment recorded as other non-current liabilities in ETP’s consolidated balance sheets: December 31, 2015 2014 Interstate transportation and storage $ 58 $ 60 Investment in Sunoco Logistics 88 41 Retail marketing 66 87 $ 212 $ 188 |
Accounts payable and accrued liabilities | Accrued and other current liabilities consisted of the following: December 31, 2015 2014 Interest payable $ 425 $ 382 Customer advances and deposits 95 103 Accrued capital expenditures 743 673 Accrued wages and benefits 218 233 Taxes payable other than income taxes 76 236 Other 386 373 Total accrued and other current liabilities $ 1,943 $ 2,000 |
Summary of fair value of financials | The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2015 and 2014 based on inputs used to derive their fair values: Fair Value Total Fair Value Measurements at December 31, 2015 Level 1 Level 2 Level 3 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 16 16 — — Swing Swaps IFERC 10 2 8 — Fixed Swaps/Futures 274 274 — — Forward Physical Swaps 4 — 4 — Power: Forwards 22 — 22 — Futures 3 3 — — Options – Puts 1 1 — — Options – Calls 1 1 — — Natural Gas Liquids – Forwards/Swaps 99 99 — — Refined Products – Futures 9 9 — — Crude – Futures 9 9 — — Total commodity derivatives 448 414 34 — Total assets $ 448 $ 414 $ 34 $ — Liabilities: Interest rate derivatives $ (171 ) $ — $ (171 ) $ — Embedded derivatives in the ETP Preferred Units (5 ) — — (5 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (16 ) (16 ) — — Swing Swaps IFERC (12 ) (2 ) (10 ) — Fixed Swaps/Futures (203 ) (203 ) — — Power: Forwards (22 ) — (22 ) — Futures (2 ) (2 ) — — Options – Puts (1 ) (1 ) — — Natural Gas Liquids – Forwards/Swaps (89 ) (89 ) — — Crude – Futures (5 ) (5 ) — — Total commodity derivatives (350 ) (318 ) (32 ) — Total liabilities $ (526 ) $ (318 ) $ (203 ) $ (5 ) Fair Value Total Fair Value Measurements at December 31, 2014 Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 3 $ — $ 3 $ — Commodity derivatives: Condensate – Forward Swaps 36 — 36 — Natural Gas: Basis Swaps IFERC/NYMEX 19 19 — — Swing Swaps IFERC 26 1 25 — Fixed Swaps/Futures 566 541 25 — Forward Physical Swaps 1 — 1 — Power: Forwards 3 — 3 — Futures 4 4 — — Natural Gas Liquids – Forwards/Swaps 69 46 23 — Refined Products – Futures 21 21 — — Total commodity derivatives 745 632 113 — Total assets $ 748 $ 632 $ 116 $ — Liabilities: Interest rate derivatives $ (155 ) $ — $ (155 ) $ — Embedded derivatives in the ETP Preferred Units (16 ) — — (16 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (18 ) (18 ) — — Swing Swaps IFERC (25 ) (2 ) (23 ) — Fixed Swaps/Futures (490 ) (490 ) — — Power: Forwards (4 ) — (4 ) — Futures (2 ) (2 ) — — Natural Gas Liquids – Forwards/Swaps (32 ) (32 ) — — Refined Products – Futures (7 ) (7 ) — — Total commodity derivatives (578 ) (551 ) (27 ) — Total liabilities $ (749 ) $ (551 ) $ (182 ) $ (16 ) |
Unobservable Inputs of Fair Value Level 3 Liabilities [Table Text Block] | The following table presents the material unobservable inputs used to estimate the fair value of ETP’s Preferred Units and the embedded derivatives in ETP’s Preferred Units: Unobservable Input December 31, 2015 Embedded derivatives in the ETP Preferred Units Credit Spread 5.33 % Volatility 37.0 % |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2015 . Balance, December 31, 2014 $ (16 ) Net unrealized gains included in other income (expense) 11 Balance, December 31, 2015 $ (5 ) |
Acquisitions and Divestitures26
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Summary Of Preliminary Assets And Liability Acquired | The following table summarizes the assets acquired and liabilities assumed recognized as of the merger date: Susser Total current assets $ 446 Property, plant and equipment 1,069 Goodwill (1) 1,734 Intangible assets 611 Other non-current assets 17 3,877 Total current liabilities 377 Long-term debt, less current maturities 564 Deferred income taxes 488 Other non-current liabilities 39 Noncontrolling interest 626 2,094 Total consideration 1,783 Cash received 67 Total consideration, net of cash received $ 1,716 (1) None of the goodwill is expected to be deductible for tax purposes. |
Selected Financial Data related To Southern Unions Discontinued Operations [Table Text Block] | The following table summarizes selected financial information related to Southern Union’s distribution operations in 2013 through MGE and NEG’s sale dates in September 2013 and December 2013, respectively: Year Ended December 31, 2013 Revenue from discontinued operations $ 415 Net income of discontinued operations, excluding effect of taxes and overhead allocations 65 |
PVR Acquisition [Member] | |
Summary Of Preliminary Assets And Liability Acquired | The total purchase price was allocated as follows: Assets At March 21, 2014 Current assets $ 149 Property, plant and equipment 2,716 Investment in unconsolidated affiliates 62 Intangible assets (average useful life of 30 years) 2,717 Goodwill (1) 370 Other non-current assets 18 Total assets acquired 6,032 Liabilities Current liabilities 168 Long-term debt 1,788 Premium related to senior notes 99 Non-current liabilities 30 Total liabilities assumed 2,085 Net assets acquired $ 3,947 (1) None of the goodwill is expected to be deductible for tax purposes. |
Eagle Rock Midstream Acquisition [Member] | |
Summary Of Preliminary Assets And Liability Acquired | The total purchase price was allocated as follows: Assets At July 1, 2014 Current assets $ 120 Property, plant and equipment 1,295 Other non-current assets 4 Goodwill 49 Total assets acquired 1,468 Liabilities Current liabilities 116 Long-term debt 499 Other non-current liabilities 12 Total liabilities assumed 627 Net assets acquired $ 841 The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. |
Investments in Unconsolidated27
Investments in Unconsolidated Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Investments in and Advances to Affiliates, Schedule of Investments [Abstract] | |
Investments in and Advances to Affiliates [Table Text Block] | The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2015 and 2014 were as follows: December 31, 2015 2014 Citrus $ 1,739 $ 1,823 AmeriGas 80 94 FEP 115 130 MEP 660 695 HPC 402 422 Sunoco LP 1,380 — Others 627 596 Total $ 5,003 $ 3,760 |
Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block] | Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, AmeriGas, Citrus, FEP, HPC, MEP and Sunoco LP (on a 100% basis) for all periods presented: December 31, 2015 2014 Current assets $ 1,646 $ 889 Property, plant and equipment, net 12,611 10,520 Other assets 5,485 2,687 Total assets $ 19,742 $ 14,096 Current liabilities $ 1,517 $ 1,983 Non-current liabilities 10,428 7,359 Equity 7,797 4,754 Total liabilities and equity $ 19,742 $ 14,096 Years Ended December 31, 2015 2014 2013 Revenue $ 20,961 $ 4,925 $ 4,695 Operating income 1,620 1,071 1,197 Net income 894 577 699 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements. |
Net Income Per Limited Partne28
Net Income Per Limited Partner Unit (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Unit, Basic and Diluted | The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit. Years Ended December 31, 2015 2014 2013 Income from continuing operations $ 1,521 $ 1,235 $ 713 Less: Income from continuing operations attributable to noncontrolling interest 157 116 239 Less: Income (loss) from continuing operations attributable to predecessor (34 ) (153 ) 35 Income from continuing operations, net of noncontrolling interest 1,398 1,272 439 General Partner’s interest in income from continuing operations 1,064 513 505 Class H Unitholder’s interest in income from continuing operations 258 217 — Class I Unitholder’s interest in income from continuing operations 94 — — Common Unitholders’ interest in income (loss) from continuing operations (18 ) 542 (66 ) Additional earnings allocated to General Partner (5 ) (4 ) (2 ) Distributions on employee unit awards, net of allocation to General Partner (16 ) (13 ) (10 ) Income (loss) from continuing operations available to Common Unitholders $ (39 ) $ 525 $ (78 ) Weighted average Common Units – basic 432.8 331.5 343.4 Basic income (loss) from continuing operations per Common Unit $ (0.09 ) $ 1.58 $ (0.23 ) Income (loss) from continuing operations available to Common Unitholders $ (39 ) $ 525 $ (78 ) Loss attributable to ETP Series A Preferred Units (6 ) — — Diluted income (loss) from continuing operations available to Common Unitholders $ (45 ) $ 525 $ (78 ) Weighted average Common Units – basic 432.8 331.5 343.4 Dilutive effect of unvested Unit Awards — 1.3 — Dilutive effect of Preferred Units 0.7 — — Weighted average Common Units – diluted 433.5 332.8 343.4 Diluted income (loss) from continuing operations per Common Unit $ (0.10 ) $ 1.58 $ (0.23 ) Basic income from discontinued operations per Common Unit $ — $ 0.19 $ 0.05 Diluted income from discontinued operations per Common Unit $ — $ 0.19 $ 0.05 |
Debt Obligations (Tables)
Debt Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Obligations [Abstract] | |
Debt instruments | Our debt obligations consist of the following: December 31, 2015 2014 ETP Debt 5.95% Senior Notes due February 1, 2015 $ — $ 750 6.125% Senior Notes due February 15, 2017 400 400 2.5% Senior Notes due June 15, 2018 650 — 6.7% Senior Notes due July 1, 2018 600 600 9.7% Senior Notes due March 15, 2019 400 400 9.0% Senior Notes due April 15, 2019 450 450 5.75% Senior Notes due September 1, 2020 (assumed from Regency) 400 — 4.15% Senior Notes due October 1, 2020 1,050 700 6.5% Senior Notes due May 15, 2021 (assumed from Regency) 500 — 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 5.875% Senior Notes due March 1, 2022 (assumed from Regency) 900 — 5.0% Senior Notes due October 1, 2022 (assumed from Regency) 700 — 3.60% Senior Notes due February 1, 2023 800 800 5.5% Senior Notes due April 15, 2023 (assumed from Regency) 700 — 4.5% Senior Notes due November 1, 2023 (assumed from Regency) 600 — 4.9% Senior Notes due February 1, 2024 350 350 7.6% Senior Notes due February 1, 2024 277 277 4.05% Senior Notes due March 15, 2025 1,000 — 4.75% Senior Notes due January 15, 2026 1,000 — 8.25% Senior Notes due November 15, 2029 267 267 4.90% Senior Notes due March 15, 2035 500 — 6.625% Senior Notes due October 15, 2036 400 400 7.5% Senior Notes due July 1, 2038 550 550 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.15% Senior Notes due March 15, 2045 1,000 — 6.125% Senior Notes due December 15, 2045 1,000 — Floating Rate Junior Subordinated Notes due November 1, 2066 545 546 ETP $3.75 billion Revolving Credit Facility due November 2019 1,362 570 Unamortized premiums, discounts and fair value adjustments, net (21 ) (1 ) Deferred debt issuance costs (147 ) (55 ) 20,633 11,404 Transwestern Debt 5.54% Senior Notes due November 17, 2016 125 125 5.64% Senior Notes due May 24, 2017 82 82 5.36% Senior Notes due December 9, 2020 175 175 5.89% Senior Notes due May 24, 2022 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 Unamortized premiums, discounts and fair value adjustments, net (1 ) (1 ) Deferred debt issuance costs (2 ) (3 ) 779 778 Panhandle Debt 6.20% Senior Notes due November 1, 2017 300 300 7.00% Senior Notes due June 15, 2018 400 400 8.125% Senior Notes due June 1, 2019 150 150 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 14, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 75 99 1,160 1,184 Sunoco, Inc. Debt 9.625% Senior Notes due April 15, 2015 — 250 5.75% Senior Notes due January 15, 2017 400 400 9.00% Debentures due November 1, 2024 65 65 Unamortized premiums, discounts and fair value adjustments, net 20 35 485 750 Sunoco Logistics Debt 6.125% Senior Notes due May 15, 2016 (1) 175 175 5.50% Senior Notes due February 15, 2020 250 250 4.4% Senior Notes due April 1, 2021 600 — 4.65% Senior Notes due February 15, 2022 300 300 3.45% Senior Notes due January 15, 2023 350 350 4.25% Senior Notes due April 1, 2024 500 500 5.95% Senior Notes due December 1, 2025 400 — 6.85% Senior Notes due February 15, 2040 250 250 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.30% Senior Notes due April 1, 2044 700 700 5.35% Senior Notes due May 15, 2045 800 800 Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015 (2) — 35 Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 562 150 Unamortized premiums, discounts and fair value adjustments, net 85 100 Deferred debt issuance costs (32 ) (26 ) 5,590 4,234 Sunoco LP Debt (3) — 683 Regency Debt, net of deferred debt issuance costs of $58 million (4) — 6,583 Other 32 223 28,679 25,839 Less: current maturities 126 1,008 $ 28,553 $ 24,831 (1) Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of December 31, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. (2) Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility matured in April 2015 and was repaid with borrowings from the Sunoco Logistics $2.50 billion Revolving Credit Facility. (3) In connection with ETE’s acquisition of Sunoco GP, the general partner of Sunoco LP, on July 1, 2015, ETP deconsolidated Sunoco LP. (4) As discussed below, the Regency senior notes were redeemed and/or assumed by the Partnership. On April 30, 2015, in connection with the Regency Merger, the Regency Revolving Credit Facility was paid off in full and terminated. |
Future maturities of long-term debt | The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $23 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: 2016 $ 301 2017 1,182 2018 1,650 2019 2,362 2020 2,937 Thereafter 20,270 Total $ 28,702 |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Schedule of Capital Units [Table Text Block] | The change in Common Units was as follows: Years Ended December 31, 2015 2014 2013 Number of Common Units, beginning of period 355.5 333.8 301.5 Common Units redeemed in connection with certain transactions (51.8 ) (18.7 ) — Common Units issued in connection with public offerings — — 13.8 Common Units issued in connection with certain acquisitions 172.2 15.8 49.5 Common Units redeemed for Class H Units — — (50.2 ) Common Units issued in connection with the Distribution Reinvestment Plan 7.7 2.8 2.3 Common Units issued in connection with Equity Distribution Agreements 21.1 21.4 16.9 Repurchases of Common Units in open-market transactions — — (0.4 ) Issuance of Common Units under equity incentive plans 0.9 0.4 0.4 Number of Common Units, end of period 505.6 355.5 333.8 |
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, including distributions on Class I Units: Total Year 2016 $ 137 2017 128 2018 105 2019 95 |
Comprehensive Income (Loss) Note [Text Block] | The following table presents the components of AOCI, net of tax: December 31, 2015 2014 Available-for-sale securities $ — $ 3 Foreign currency translation adjustment (4 ) (3 ) Net loss on commodity related hedges — (1 ) Actuarial gain (loss) related to pensions and other postretirement benefits 8 (57 ) Investments in unconsolidated affiliates, net — 2 Total AOCI, net of tax $ 4 $ (56 ) |
Schedule of taxes related to accumulated other comprehensive income [Table Text Block] | The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss): December 31, 2015 2014 Available-for-sale securities $ (2 ) $ (1 ) Foreign currency translation adjustment 4 2 Actuarial loss (gain) relating to pension and other postretirement benefits 7 (37 ) Total $ 9 $ (36 ) |
ETP [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2012 February 7, 2013 February 14, 2013 $ 0.8938 March 31, 2013 May 6, 2013 May 15, 2013 0.8938 June 30, 2013 August 5, 2013 August 14, 2013 0.8938 September 30, 2013 November 4, 2013 November 14, 2013 0.9050 December 31, 2013 February 7, 2014 February 14, 2014 0.9200 March 31, 2014 May 5, 2014 May 15, 2014 0.9350 June 30, 2014 August 4, 2014 August 14, 2014 0.9550 September 30, 2014 November 3, 2014 November 14, 2014 0.9750 December 31, 2014 February 6, 2015 February 13, 2015 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 September 30, 2015 November 5, 2015 November 16, 2015 1.0550 December 31, 2015 February 8, 2016 February 16, 2016 1.0550 |
Sunoco Logistics [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2012 February 8, 2013 February 14, 2013 $ 0.2725 March 31, 2013 May 9, 2013 May 15, 2013 0.2863 June 30, 2013 August 8, 2013 August 14, 2013 0.3000 September 30, 2013 November 8, 2013 November 14, 2013 0.3150 December 31, 2013 February 10, 2014 February 14, 2014 0.3312 March 31, 2014 May 9, 2014 May 15, 2014 0.3475 June 30, 2014 August 8, 2014 August 14, 2014 0.3650 September 30, 2014 November 7, 2014 November 14, 2014 0.3825 December 31, 2014 February 9, 2015 February 13, 2015 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380 September 30, 2015 November 9, 2015 November 13, 2015 0.4580 December 31, 2015 February 8, 2016 February 12, 2016 0.4790 |
Unit-Based Compensation Plans31
Unit-Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Deferred Compensation Arrangements [Abstract] | |
Activity of the awards granted to employees and non-employee directors | The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2014 3.5 $ 53.83 Awards granted 2.1 35.21 Awards vested (1.2 ) 48.67 Awards forfeited (0.4 ) 55.44 Conversion of RGP unit awards to ETP unit awards 0.8 58.88 Unvested awards as of December 31, 2015 4.8 47.61 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows: Years Ended December 31, 2015 2014 2013 Current expense (benefit): Federal $ (274 ) $ 321 $ 51 State (51 ) 86 (2 ) Total (325 ) 407 49 Deferred expense (benefit): Federal 231 (50 ) (6 ) State (29 ) 1 54 Total 202 (49 ) 48 Total income tax expense (benefit) from continuing operations $ (123 ) $ 358 $ 97 |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Historically, our effective rate differed from the statutory rate primarily due to Partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3 ) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2015 , 2014 and 2013 is as follows: December 31, 2015 December 31, 2014 December 31, 2013 Corporate Subsidiaries (1) Consolidated (2) Corporate Subsidiaries (1) Consolidated (2) Corporate Subsidiaries (1) Consolidated (2) Income tax expense (benefit) at U.S. statutory rate of 35 percent $ (25 ) $ (25 ) $ 217 $ 217 $ (166 ) $ (166 ) Increase (reduction) in income taxes resulting from: Nondeductible goodwill — — — — 241 241 Nondeductible goodwill included in the Lake Charles LNG Transaction — — 105 105 — — State income taxes (net of federal income tax effects) (56 ) (37 ) 9 54 31 36 Dividend Received Deduction (24 ) (24 ) — — — — Premium on debt retirement — — (10 ) (10 ) — — Audit Settlement (7 ) (7 ) — — — — Foreign — — (8 ) (8 ) — — Other (30 ) (30 ) — — (13 ) (14 ) Income tax expense (benefit) from continuing operations $ (142 ) $ (123 ) $ 313 $ 358 $ 93 $ 97 (1) Includes ETP Holdco, Susser Holdings Corporation, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd., Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. Susser Holding Corporation, Susser Petroleum Property Company LLC and Aloha Petroleum Ltd. were deconsolidated from these financial statements in July 2015 due to the contribution of Susser Holding Corporation to Sunoco LP and the acquisition by ETE of 100% of the membership interest of Sunoco GP, the general partner of Sunoco LP (See Note 3 ). (2) Includes ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries. |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2015 2014 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 155 $ 116 Pension and other postretirement benefits 36 47 Long term debt 61 53 Other 142 111 Total deferred income tax assets 394 327 Valuation allowance (121 ) (84 ) Net deferred income tax assets $ 273 $ 243 Deferred income tax liabilities: Properties, plants and equipment $ (1,305 ) $ (1,506 ) Inventory — (153 ) Investment in unconsolidated affiliates (2,889 ) (2,528 ) Trademarks (112 ) (355 ) Other (49 ) (32 ) Total deferred income tax liabilities (4,355 ) (4,574 ) Accumulated deferred income taxes $ (4,082 ) $ (4,331 ) |
Balance Sheet Classification of Deferred Taxes [Table Text Block] | The table below provides a rollforward of the net deferred income tax liability as follows: December 31, 2015 2014 Net deferred income tax liability, beginning of year $ (4,331 ) $ (3,903 ) Susser acquisition — (488 ) ETE Acquisition of general partner of Sunoco LP 490 — Tax provision (including discontinued operations) (202 ) 60 Other (39 ) — Net deferred income tax liability, end of year $ (4,082 ) $ (4,331 ) |
Schedule of Unrecognized Tax Benefits Rollforward [Table Text Block] | The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2015 2014 2013 Balance at beginning of year $ 440 $ 429 $ 27 Additions attributable to tax positions taken in the current year — 20 — Additions attributable to tax positions taken in prior years 178 (1 ) 406 Settlements — (5 ) — Lapse of statute (8 ) (3 ) (4 ) Balance at end of year $ 610 $ 440 $ 429 |
Regulatory Matters, Commitmen33
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
Operating Leases of Lessee Disclosure [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 2058 . 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: Years Ended December 31, 2015 2014 2013 Rental expense (1) $ 176 $ 159 $ 151 Less: Sublease rental income (16 ) (26 ) (24 ) Rental expense, net $ 160 $ 133 $ 127 (1) Includes contingent rentals totaling $26 million , $24 million and $22 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. |
Future Minimum Lease Commitments | Future minimum lease commitments for such leases are: Years Ending December 31: 2016 $ 57 2017 53 2018 44 2019 39 2020 40 Thereafter 252 Future minimum lease commitments 485 Less: Sublease rental income (34 ) Net future minimum lease commitments $ 451 |
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. December 31, 2015 2014 Current $ 41 $ 41 Non-current 326 360 Total environmental liabilities $ 367 $ 401 |
Derivative assets and liabilt34
Derivative assets and liabilties (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |
Outstanding commodity-related derivatives | The following table details our outstanding commodity-related derivatives: December 31, 2015 December 31, 2014 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (602,500 ) 2016-2017 (232,500 ) 2015 Basis Swaps IFERC/NYMEX (1) (31,240,000 ) 2016-2017 (13,907,500 ) 2015-2016 Options – Calls — — 5,000,000 2015 Power (Megawatt): Forwards 357,092 2016-2017 288,775 2015 Futures (109,791 ) 2016 (156,000 ) 2015 Options – Puts 260,534 2016 (72,000 ) 2015 Options – Calls 1,300,647 2016 198,556 2015 Crude (Bbls) – Futures (591,000 ) 2016-2017 — — (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (6,522,500 ) 2016-2017 57,500 2015 Swing Swaps IFERC 71,340,000 2016-2017 46,150,000 2015 Fixed Swaps/Futures (14,380,000 ) 2016-2018 (34,304,000 ) 2015-2016 Forward Physical Contracts 21,922,484 2016-2017 (9,116,777 ) 2015 Natural Gas Liquid (Bbls) – Forwards/Swaps (8,146,800 ) 2016-2018 (4,417,400 ) 2015 Refined Products (Bbls) – Futures (993,000 ) 2016-2017 13,745,755 2015 Corn (Bushels) – Futures 1,185,000 2016 — — Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (37,555,000 ) 2016 (39,287,500 ) 2015 Fixed Swaps/Futures (37,555,000 ) 2016 (39,287,500 ) 2015 Hedged Item – Inventory 37,555,000 2016 39,287,500 2015 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Interest rate swaps outstanding | The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding December 31, 2015 December 31, 2014 July 2015 (2) Forward-starting to pay a fixed rate of 3.38% and receive a floating rate $ — $ 200 July 2016 (3) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 200 200 July 2017 (4) Forward-starting to pay a fixed rate of 3.84% and receive a floating rate 300 300 July 2018 (4) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 200 July 2019 (4) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 300 December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 — March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 — February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% — 200 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have terms of 10 years with a mandatory termination date the same as the effective date. (3) Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date. (4) 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 | The following table provides a summary of our derivative assets and liabilities: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives December 31, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 38 $ 43 $ (3 ) $ — 38 43 (3 ) — Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 353 617 (306 ) (577 ) Commodity derivatives 57 107 (41 ) (23 ) Interest rate derivatives — 3 (171 ) (155 ) Embedded derivatives in ETP Preferred Units — — (5 ) (16 ) 410 727 (523 ) (771 ) Total derivatives $ 448 $ 770 $ (526 ) $ (771 ) |
Offsetting Assets Table Text Block [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: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives without offsetting agreements Derivative assets (liabilities) $ — $ 3 $ (176 ) $ (171 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 57 107 (41 ) (23 ) Broker cleared derivative contracts Other current assets 391 660 (309 ) (577 ) 448 770 (526 ) (771 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (17 ) (19 ) 17 19 Payments on margin deposit Other current assets (309 ) (577 ) 309 577 Total net derivatives $ 122 $ 174 $ (200 ) $ (175 ) |
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss) [Table Text Block] | Change in Value Recognized in OCI on Derivatives (Effective Portion) Years Ended December 31, 2015 2014 2013 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ — $ (1 ) Total $ — $ — $ (1 ) |
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block] | Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Years Ended December 31, 2015 2014 2013 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ (3 ) $ 4 Total $ — $ (3 ) $ 4 |
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2015 2014 2013 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 21 $ (8 ) $ 8 Total $ 21 $ (8 ) $ 8 |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2015 2014 2013 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (11 ) $ (6 ) $ (11 ) Commodity derivatives – Non-trading Cost of products sold 23 199 (21 ) Commodity contracts – Non-trading Deferred gas purchases — — (3 ) Interest rate derivatives Gains (losses) on interest rate derivatives (18 ) (157 ) 44 Embedded derivatives Other, net 12 3 6 Total $ 6 $ 39 $ 15 |
Retirement Benefits Retirement
Retirement Benefits Retirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Schedule of Defined Benefit Plans Disclosures [Table Text Block] | The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2015 December 31, 2014 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 718 $ 65 $ 202 $ 632 $ 61 $ 223 Interest cost 23 2 4 28 3 5 Amendments — — — — — 1 Benefits paid, net (46 ) (8 ) (20 ) (45 ) (9 ) (28 ) Actuarial (gain) loss and other 16 (2 ) (6 ) 130 10 2 Settlements (691 ) — — (27 ) — — Dispositions — — — — — (1 ) Benefit obligation at end of period 20 57 180 718 65 202 Change in plan assets: Fair value of plan assets at beginning of period 598 — 265 600 — 284 Return on plan assets and other 16 — — 70 — 6 Employer contributions 138 — 8 — — 8 Benefits paid, net (46 ) — (20 ) (45 ) — (28 ) Settlements (691 ) — — (27 ) — — Dispositions — — — — — (5 ) Fair value of plan assets at end of period 15 — 253 598 — 265 Amount underfunded (overfunded) at end of period $ 5 $ 57 $ (73 ) $ 120 $ 65 $ (63 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 97 $ — $ — $ 90 Current liabilities — (9 ) (2 ) — (9 ) (2 ) Non-current liabilities (5 ) (48 ) (22 ) (120 ) (56 ) (25 ) $ (5 ) $ (57 ) $ 73 $ (120 ) $ (65 ) $ 63 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain $ 2 $ 4 $ (17 ) $ 18 $ 7 $ (20 ) Prior service cost — — 15 — — 17 $ 2 $ 4 $ (2 ) $ 18 $ 7 $ (3 ) |
Schedule of Accumulated and Projected Benefit Obligations [Table Text Block] | The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2015 December 31, 2014 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 20 $ 57 N/A $ 718 $ 65 N/A Accumulated benefit obligation 20 57 $ 180 718 65 $ 202 Fair value of plan assets 15 — 253 598 — 265 |
Schedule of Net Benefit Costs [Table Text Block] | December 31, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Interest cost $ 25 $ 4 $ 31 $ 5 Expected return on plan assets (16 ) (8 ) (40 ) (8 ) Prior service cost amortization — 1 — 1 Actuarial loss amortization — — (1 ) (1 ) Settlements 32 — (4 ) — Net periodic benefit cost $ 41 $ (3 ) $ (14 ) $ (3 ) |
Schedule of Benefit Obligations Assumptions [Table Text Block] | The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.59 % 2.38 % 3.62 % 2.24 % Rate of compensation increase N/A N/A N/A N/A |
Schedule or Description of Weighted Average Discount Rate [Table Text Block] | The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2015 December 31, 2014 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.65 % 2.79 % 4.65 % 3.02 % Expected return on assets: Tax exempt accounts 7.50 % 7.00 % 7.50 % 7.00 % Taxable accounts N/A 4.50 % N/A 4.50 % Rate of compensation increase N/A N/A N/A N/A |
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block] | The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: December 31, 2015 2014 Health care cost trend rate 7.16 % 7.09 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.39 % 5.41 % Year that the rate reaches the ultimate trend rate 2018 2018 |
Fair Value of Plan Assets [Table Text Block] | The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2015 Using Fair Value Hierarchy Fair Value as of December 31, 2015 Level 1 Level 2 Level 3 Asset category: Mutual funds (1) $ 15 — 15 — Total $ 15 $ — $ 15 $ — (1) Comprised of approximately 100% equities as of December 31, 2015 . Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 25 $ 25 $ — $ — Mutual funds (1) 110 — 110 — Fixed income securities 463 — 463 — Total $ 598 $ 25 $ 573 $ — (1) Comprised of approximately 100% equities as of December 31, 2014 . The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2015 Using Fair Value Hierarchy Fair Value as of December 31, 2015 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 133 133 — — Fixed income securities 102 — 102 — Total $ 253 $ 151 $ 102 $ — (1) Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015 . Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 9 $ 9 $ — $ — Mutual funds (1) 131 131 — — Fixed income securities 125 — 125 — Total $ 265 $ 140 $ 125 $ — (1) Primarily comprised of approximately 56% equities, 38% fixed income securities and 6% cash as of December 31, 2014 . The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. |
Schedule of Expected Benefit Payments [Table Text Block] | Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Pension Benefits Years Funded Plans Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2016 $ 20 $ 9 $ 21 2017 — 7 20 2018 — 7 19 2019 — 6 17 2020 — 6 16 2021 – 2025 — 2 58 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Schedule Of Related Party Transactions By Related Party [Table Text Block] | The following table summarizes the affiliate revenues on our consolidated statements of operations: Years Ended December 31, 2015 2014 2013 Affiliated revenues $ 417 $ 965 $ 1,442 |
Related Party Balances For Period Presented [Table Text Block] | The following table summarizes the related company balances on our consolidated balance sheets: December 31, 2015 2014 Accounts receivable from related companies: Sunoco LP $ 3 $ — ETE 110 11 PES 10 6 FGT 13 9 Lake Charles LNG 36 3 Trans-Pecos Pipeline, LLC 29 — Comanche Trail Pipeline, LLC 22 — Other 45 110 Total accounts receivable from related companies $ 268 $ 139 Accounts payable to related companies: Sunoco LP $ 5 $ — FGT 1 2 Lake Charles LNG 3 2 Other 16 21 Total accounts payable to related companies $ 25 $ 25 |
Reportable Segments (Tables)
Reportable Segments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Reportable Segments [Abstract] | |
Reportable segments | The following tables present financial information by segment: Years Ended December 31, 2015 2014 2013 Revenues: Intrastate transportation and storage: Revenues from external customers $ 1,912 $ 2,645 $ 2,242 Intersegment revenues 338 212 210 2,250 2,857 2,452 Interstate transportation and storage: Revenues from external customers 1,008 1,057 1,270 Intersegment revenues 17 15 39 1,025 1,072 1,309 Midstream: Revenues from external customers 2,622 4,770 3,220 Intersegment revenues 2,449 2,053 1,056 5,071 6,823 4,276 Liquids transportation and services: Revenues from external customers 3,232 3,730 2,025 Intersegment revenues 249 181 101 3,481 3,911 2,126 Investment in Sunoco Logistics: Revenues from external customers 10,302 17,920 16,480 Intersegment revenues 184 168 159 10,486 18,088 16,639 Retail marketing: Revenues from external customers 12,478 22,484 21,004 Intersegment revenues 4 3 8 12,482 22,487 21,012 All other: Revenues from external customers 2,738 2,869 2,094 Intersegment revenues 554 462 503 3,292 3,331 2,597 Eliminations (3,795 ) (3,094 ) (2,076 ) Total revenues $ 34,292 $ 55,475 $ 48,335 Years Ended December 31, 2015 2014 2013 Cost of products sold: Intrastate transportation and storage $ 1,554 $ 2,169 $ 1,737 Midstream 3,266 4,893 3,130 Liquids transportation and services 2,595 3,166 1,654 Investment in Sunoco Logistics 9,307 17,135 15,600 Retail marketing 11,174 21,154 20,150 All other 2,855 2,975 2,337 Eliminations (3,722 ) (3,078 ) (2,028 ) Total cost of products sold $ 27,029 $ 48,414 $ 42,580 Years Ended December 31, 2015 2014 2013 Depreciation, depletion and amortization: Intrastate transportation and storage $ 129 $ 125 $ 122 Interstate transportation and storage 210 203 244 Midstream 720 569 335 Liquids transportation and services 126 113 91 Investment in Sunoco Logistics 382 296 265 Retail marketing 190 189 114 All other 172 174 125 Total depreciation, depletion and amortization $ 1,929 $ 1,669 $ 1,296 Years Ended December 31, 2015 2014 2013 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 32 $ 27 $ 30 Interstate transportation and storage 197 196 182 Midstream (19 ) 10 1 Liquids transportation and services (2 ) (3 ) (2 ) Investment in Sunoco Logistics 21 23 18 Retail marketing 194 2 2 All other 46 77 5 Total equity in earnings of unconsolidated affiliates $ 469 $ 332 $ 236 Years Ended December 31, 2015 2014 2013 Segment Adjusted EBITDA: Intrastate transportation and storage $ 543 $ 559 $ 521 Interstate transportation and storage 1,155 1,212 1,368 Midstream 1,250 1,318 757 Liquids transportation and services 731 591 350 Investment in Sunoco Logistics 1,153 971 871 Retail marketing 583 731 325 All other 299 328 212 Total Segment Adjusted EBITDA 5,714 5,710 4,404 Depreciation, depletion and amortization (1,929 ) (1,669 ) (1,296 ) Interest expense, net of interest capitalized (1,291 ) (1,165 ) (1,013 ) Gain on sale of AmeriGas common units — 177 87 Impairment losses (339 ) (370 ) (689 ) Gains (losses) on interest rate derivatives (18 ) (157 ) 44 Non-cash unit-based compensation expense (79 ) (68 ) (54 ) Unrealized gains (losses) on commodity risk management activities (65 ) 112 42 Inventory valuation adjustments (104 ) (473 ) 3 Losses on extinguishments of debt (43 ) (25 ) (7 ) Non-operating environmental remediation — — (168 ) Adjusted EBITDA related to discontinued operations — (27 ) (76 ) Adjusted EBITDA related to unconsolidated affiliates (937 ) (748 ) (722 ) Equity in earnings of unconsolidated affiliates 469 332 236 Other, net 20 (36 ) 19 Income from continuing operations before income tax expense $ 1,398 $ 1,593 $ 810 December 31, 2015 2014 2013 Assets: Intrastate transportation and storage $ 4,882 $ 4,983 $ 5,048 Interstate transportation and storage 11,345 10,779 11,537 Midstream 17,111 15,562 7,847 Liquids transportation and services 7,235 4,568 4,321 Investment in Sunoco Logistics 15,423 13,619 11,650 Retail marketing 3,218 8,917 3,936 All other 5,959 4,090 5,561 Total assets $ 65,173 $ 62,518 $ 49,900 Years Ended December 31, 2015 2014 2013 Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis): Intrastate transportation and storage $ 105 $ 169 $ 47 Interstate transportation and storage 860 411 152 Midstream 2,172 1,298 1,114 Liquids transportation and services 2,109 427 448 Investment in Sunoco Logistics 2,126 2,510 1,018 Retail marketing 412 259 176 All other 383 420 372 Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) $ 8,167 $ 5,494 $ 3,327 December 31, 2015 2014 2013 Advances to and investments in unconsolidated affiliates: Intrastate transportation and storage $ 406 $ 423 $ 443 Interstate transportation and storage 2,516 2,649 2,588 Midstream 117 138 36 Liquids transportation and services 32 31 29 Investment in Sunoco Logistics 247 226 125 Retail marketing 1,541 19 22 All other 144 274 807 Total advances to and investments in unconsolidated affiliates $ 5,003 $ 3,760 $ 4,050 |
Quarterly Financial Data (Table
Quarterly Financial Data (Tables) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Quarterly Financial Data [Abstract] | ||
Schedule of Quarterly Financial Information [Table Text Block] | Quarters Ended March 31 June 30 September 30 December 31 Total Year 2015: Revenues $ 10,326 $ 11,540 $ 6,601 $ 5,825 $ 34,292 Operating income 608 888 576 187 2,259 Net income 268 839 393 21 1,521 Common Unitholders’ interest in net income (loss) (48 ) 298 59 (327 ) (18 ) Basic net income (loss) per Common Unit $ (0.17 ) $ 0.67 $ 0.11 $ (0.68 ) $ (0.09 ) Diluted net income (loss) per Common Unit $ (0.17 ) $ 0.67 $ 0.10 $ (0.68 ) $ (0.10 ) | Quarters Ended March 31 June 30 September 30 December 31 Total Year 2014: Revenues $ 13,027 $ 14,088 $ 14,933 $ 13,427 $ 55,475 Operating income 706 769 809 159 2,443 Net income (loss) 483 548 513 (245 ) 1,299 Common Unitholders’ interest in net income (loss) 253 295 148 (90 ) 606 Basic net income (loss) per Common Unit $ 0.76 $ 0.92 $ 0.44 $ (0.28 ) $ 1.77 Diluted net income (loss) per Common Unit $ 0.76 $ 0.92 $ 0.44 $ (0.28 ) $ 1.77 |
Operations and Organization (Na
Operations and Organization (Narrative) (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Oct. 31, 2015 | Jul. 31, 2015 | Apr. 30, 2015 | Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Payments to Acquire Businesses, Gross | $ 382 | ||||||
Stock Repurchased During Period, Shares | 0 | 0 | (400,000) | ||||
Dropdown of Sunoco LLC Interest [Member] | |||||||
Payments to Acquire Businesses, Gross | $ 775 | ||||||
Business Combination, Consideration Transferred | $ 816 | ||||||
Dropdown of Sunoco LLC Interest [Member] | Sunoco, LLC [Member] | |||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 68.42% | ||||||
Dropdown of Sunoco LLC Interest [Member] | Legacy Sunoco, Inc. [Member] | |||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||||
Dropdown of Sunoco LLC Interest [Member] | Sunoco LP [Member] | |||||||
Payments to Acquire Businesses, Gross | $ 2,030 | ||||||
Sale of Stock, Number of Shares Issued in Transaction | 5,700,000 | ||||||
Business Combination, Consideration Transferred | $ 2,230 | ||||||
Sunoco LP Exchange [Member] | |||||||
Stock Repurchased During Period, Shares | 21,000,000 | ||||||
Sunoco LP Exchange [Member] | Sunoco GP [Member] | |||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||||
Regency Merger [Member] | |||||||
Business Acquisition, Number Of Share Received In Exchange Of Each Share | 0.4124 | ||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 172,200,000 | ||||||
Relinquishment of Incentive Distributions | $ 320 | ||||||
ETP Subsidiaries [Member] | Regency Merger [Member] | |||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 15,500,000 | ||||||
ETP Series A Preferred Units [Member] | Regency Merger [Member] | |||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 1,900,000 | ||||||
Relinquishment, Year 1 [Member] | Regency Merger [Member] | |||||||
Relinquishment of Incentive Distributions | 80 | ||||||
Relinquishment, Years 2 through 5 [Member] | Regency Merger [Member] | |||||||
Relinquishment of Incentive Distributions | $ 60 |
Estimates, Significant Accoun40
Estimates, Significant Accounting Policies and Balance Sheet Detials (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Aug. 29, 2014 | |
Deferred Tax Liabilities, Gross | $ 4,355 | $ 4,574 | ||
Tangible Asset Impairment Charges | 110 | |||
ARO Underlying Asset | 18 | |||
Asset Retirement Obligation, Legally Restricted Assets, Fair Value | 6 | |||
Impairment of Intangible Assets, Finite-lived | 24 | |||
Inventory Write-down | 104 | |||
Impairment losses | 205 | 370 | ||
Net increase in goodwill | (2,210) | |||
Goodwill, Written off Related to Sale of Business Unit | 2,018 | 184 | ||
Long-term Debt, Fair Value | 25,710 | 26,910 | ||
Goodwill acquired | 0 | 2,340 | ||
Goodwill | 5,428 | 7,642 | $ 5,856 | |
Long-term Debt | $ 28,679 | 25,839 | ||
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member] | ||||
Useful Lives | 3 years | |||
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member] | ||||
Useful Lives | 46 years | |||
Maximum [Member] | Patents [Member] | ||||
Useful Lives | 9 years | |||
Interstate Transportation and Storage [Member] | ||||
Impairment losses | $ (99) | 0 | ||
Goodwill, Written off Related to Sale of Business Unit | 0 | 184 | ||
Goodwill acquired | 0 | 0 | ||
Goodwill | 912 | 1,011 | 1,195 | |
Liquids Transportation And Services [Member] | ||||
Impairment losses | (106) | 0 | ||
Goodwill, Written off Related to Sale of Business Unit | 0 | 0 | ||
Goodwill acquired | 0 | 0 | ||
Goodwill | 326 | 432 | 432 | |
Midstream [Member] | ||||
Impairment losses | 0 | (370) | ||
Goodwill, Written off Related to Sale of Business Unit | 0 | 0 | ||
Goodwill acquired | 0 | 451 | ||
Goodwill | 718 | 767 | 686 | |
Retail Marketing [Member] | ||||
Excise Taxes Collected | $ 1,850 | 2,460 | 2,220 | |
Impairment losses | 0 | |||
Goodwill, Written off Related to Sale of Business Unit | $ 2,018 | 0 | ||
Goodwill acquired | 0 | 1,862 | ||
Goodwill | $ 1,289 | 3,307 | $ 1,445 | |
Amount Reclassed From ASU 2015-17 [Member] | ||||
Deferred Tax Liabilities, Gross | $ 85 | |||
Susser Merger [Member] | ||||
Goodwill1 | $ 1,734 |
Estimates, Significant Accoun41
Estimates, Significant Accounting Policies and Balance Sheet Detials (Net change in operating assets and liabilities (net of acquisitions) included in cash flows) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |||
Accounts receivable | $ 819 | $ 600 | $ (557) |
Accounts receivable from related companies | (243) | (22) | 26 |
Inventories | (351) | 51 | (254) |
Exchanges receivable | 13 | 18 | (8) |
Other current assets | (191) | 132 | (58) |
Other non-current assets, net | 188 | (6) | (45) |
Accounts payable | (1,215) | (851) | 542 |
Accounts payable to related companies | (160) | 3 | (143) |
Exchanges payable | (78) | (99) | 128 |
Accrued and other current liabilities | (5) | (92) | 211 |
Other non-current liabilities | (219) | (73) | 147 |
Price risk management assets and liabilities, net | 75 | 19 | (147) |
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ (1,367) | $ (320) | $ (158) |
Estimates, Significant Accoun42
Estimates, Significant Accounting Policies and Balance Sheet Detials (Non-cash investing and financing activities and supplemental cash flow information) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Accrued capital expenditures | $ 896 | $ 643 | $ 226 |
Net gains from subsidiary common unit transactions | 300 | 175 | 0 |
Capital Contributions from Noncontrolling Interest | 34 | 0 | 0 |
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions | 0 | 564 | 0 |
Noncontrolling Interest, Increase from Sale of Parent Equity Interest | 1,946 | 0 | 0 |
SUPPLEMENTAL CASH FLOW INFORMATION: | |||
Cash paid for interest, net of interest capitalized | 1,467 | 1,232 | 1,049 |
Cash paid for income taxes | 71 | 344 | 58 |
Regency Merger [Member] | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | 9,250 | 0 | 0 |
Susser Merger [Member] | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | 0 | 908 | 0 |
Lake Charles LNG Transaction [Member] | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Lake Charles LNG Transaction | 0 | 1,167 | 0 |
ETP Holdco Acquisition | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | 0 | 0 | (2,464) |
Predecessor Acquisitions [Member] | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | 0 | 4,281 | 0 |
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions | 0 | 2,386 | 0 |
Bakken Pipeline Transaction [Member] | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Lake Charles LNG Transaction | 999 | 0 | 0 |
Sunoco LP Exchange [Member] | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Lake Charles LNG Transaction | 52 | 0 | 0 |
Class H Units | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | $ 0 | $ 0 | $ (1,514) |
Estimates, Significant Accoun43
Estimates, Significant Accounting Policies and Balance Sheet Detials (Inventory) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | ||
Natural gas and NGLs | $ 415 | $ 392 |
Crude oil | 424 | 364 |
Refined products | 104 | 392 |
Spare parts and other | 270 | 312 |
Total inventories | $ 1,213 | $ 1,460 |
Estimates, Significant Accoun44
Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Current Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | ||
Deposits paid to vendors | $ 74 | $ 65 |
Income Taxes Receivable, Current | 291 | 17 |
Prepaid expenses and other | 137 | 200 |
Total other current assets | $ 502 | $ 282 |
Estimates, Significant Accoun45
Estimates, Significant Accounting Policies and Balance Sheet Detials (Components and useful lives of property, plant and equipment) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Property, Plant and Equipment, Gross | $ 50,869 | $ 43,404 |
Less - Accumulated depreciation | (5,782) | (4,497) |
Property, plant and equipment, net | 45,087 | 38,907 |
Land and improvements | ||
Property, Plant and Equipment, Gross | 686 | 1,307 |
Buildings and improvements (1 to 45 years) | ||
Property, Plant and Equipment, Gross | 1,526 | 1,918 |
Pipelines and equipment (5 to 83 years) | ||
Property, Plant and Equipment, Gross | 33,148 | 27,164 |
Natural gas and NGL storage facilities (5 to 46 years) | ||
Property, Plant and Equipment, Gross | 391 | 1,215 |
Bulk storage, equipment and facilities (2 to 83 years) | ||
Property, Plant and Equipment, Gross | 2,853 | 2,583 |
Tanks and other equipment (5 to 40 years) | ||
Property, Plant and Equipment, Gross | 60 | 58 |
Retail equipment (2 to 99 years) | ||
Property, Plant and Equipment, Gross | 401 | 515 |
Vehicles (1 to 25 years) | ||
Property, Plant and Equipment, Gross | 220 | 203 |
Right of way (20 to 83 years) | ||
Property, Plant and Equipment, Gross | 2,573 | 2,445 |
Furniture and fixtures (2 to 25 years) | ||
Property, Plant and Equipment, Gross | 55 | 57 |
Linepack | ||
Property, Plant and Equipment, Gross | 61 | 119 |
Pad gas | ||
Property, Plant and Equipment, Gross | 44 | 44 |
Natural resources | ||
Property, Plant and Equipment, Gross | 484 | 454 |
Other (1 to 30 years) | ||
Property, Plant and Equipment, Gross | 523 | 979 |
Construction Work-In-Process [Member] | ||
Property, Plant and Equipment, Gross | $ 7,844 | $ 4,343 |
Minimum [Member] | Buildings and improvements (1 to 45 years) | ||
Property, plant and equipment useful life, minimum in years | 1 year | |
Minimum [Member] | Pipelines and equipment (5 to 83 years) | ||
Property, plant and equipment useful life, minimum in years | 5 years | |
Minimum [Member] | Natural gas and NGL storage facilities (5 to 46 years) | ||
Property, plant and equipment useful life, minimum in years | 5 years | |
Minimum [Member] | Bulk storage, equipment and facilities (2 to 83 years) | ||
Property, plant and equipment useful life, minimum in years | 2 years | |
Minimum [Member] | Tanks and other equipment (5 to 40 years) | ||
Property, plant and equipment useful life, minimum in years | 5 years | |
Minimum [Member] | Retail equipment (2 to 99 years) | ||
Property, plant and equipment useful life, minimum in years | 2 years | |
Minimum [Member] | Vehicles (1 to 25 years) | ||
Property, plant and equipment useful life, minimum in years | 1 year | |
Minimum [Member] | Right of way (20 to 83 years) | ||
Property, plant and equipment useful life, minimum in years | 20 years | |
Minimum [Member] | Furniture and fixtures (2 to 25 years) | ||
Property, plant and equipment useful life, minimum in years | 2 years | |
Minimum [Member] | Other (1 to 30 years) | ||
Property, plant and equipment useful life, minimum in years | 1 year | |
Maximum [Member] | Buildings and improvements (1 to 45 years) | ||
Property, plant and equipment useful life, minimum in years | 45 years | |
Maximum [Member] | Pipelines and equipment (5 to 83 years) | ||
Property, plant and equipment useful life, minimum in years | 83 years | |
Maximum [Member] | Natural gas and NGL storage facilities (5 to 46 years) | ||
Property, plant and equipment useful life, minimum in years | 46 years | |
Maximum [Member] | Bulk storage, equipment and facilities (2 to 83 years) | ||
Property, plant and equipment useful life, minimum in years | 83 years | |
Maximum [Member] | Tanks and other equipment (5 to 40 years) | ||
Property, plant and equipment useful life, minimum in years | 40 years | |
Maximum [Member] | Retail equipment (2 to 99 years) | ||
Property, plant and equipment useful life, minimum in years | 99 years | |
Maximum [Member] | Vehicles (1 to 25 years) | ||
Property, plant and equipment useful life, minimum in years | 25 years | |
Maximum [Member] | Right of way (20 to 83 years) | ||
Property, plant and equipment useful life, minimum in years | 83 years | |
Maximum [Member] | Furniture and fixtures (2 to 25 years) | ||
Property, plant and equipment useful life, minimum in years | 25 years | |
Maximum [Member] | Other (1 to 30 years) | ||
Property, plant and equipment useful life, minimum in years | 30 years |
Estimates, Significant Accoun46
Estimates, Significant Accounting Policies and Balance Sheet Detials (Schedule of Property, Plant and Equipment Depreciation and Capitalized Interest Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |||
Depreciation and depletion expense | $ 1,713 | $ 1,457 | $ 1,202 |
Capitalized interest, excluding AFUDC | $ 163 | $ 101 | $ 45 |
Estimates, Significant Accoun47
Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Non-Current Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | ||
Unamortized financing costs(1) | $ 11 | $ 30 |
Regulatory assets | 90 | 85 |
Deferred charges | 198 | 220 |
Restricted funds | 192 | 177 |
Other | 45 | 132 |
Total other non-current assets, net | $ 536 | $ 644 |
Estimates, Significant Accoun48
Estimates, Significant Accounting Policies and Balance Sheet Detials (Intangible assets) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Gross Carrying Amount | $ 5,012 | $ 6,023 |
Accumulated Amortization | (591) | (497) |
Customer relationships, contracts and agreements (3 to 46 years) [Member] | ||
Gross Carrying Amount | 4,601 | 5,067 |
Accumulated Amortization | (554) | (464) |
Patents (9 years) [Member] | ||
Gross Carrying Amount | 48 | 48 |
Accumulated Amortization | (16) | (11) |
Trade Names [Member] | ||
Gross Carrying Amount | 66 | 556 |
Accumulated Amortization | (18) | (15) |
Other Amortizable Intangible Assets [Member] | ||
Gross Carrying Amount | 6 | 36 |
Accumulated Amortization | (3) | (7) |
Total Amortizable Intangible Assets [Member] | ||
Gross Carrying Amount | 4,721 | 5,707 |
Accumulated Amortization | (591) | (497) |
Non-amortizable intangible assets - Trademarks [Member] | ||
Gross Carrying Amount | 291 | 316 |
Accumulated Amortization | $ 0 | $ 0 |
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member] | ||
Useful Lives | 46 years | |
Maximum [Member] | Patents (9 years) [Member] | ||
Useful Lives | 9 years | |
Maximum [Member] | Trade Names [Member] | ||
Useful Lives | 15 years | |
Maximum [Member] | Other Amortizable Intangible Assets [Member] | ||
Useful Lives | 15 years | |
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member] | ||
Useful Lives | 3 years | |
Minimum [Member] | Other Amortizable Intangible Assets [Member] | ||
Useful Lives | 1 year |
Estimates, Significant Accoun49
Estimates, Significant Accounting Policies and Balance Sheet Detials (Amortization expense of intangible assets) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Depreciation And Amortization [Member] | |||
Reported in depreciation and amortization | $ 216 | $ 212 | $ 117 |
Estimates, Significant Accoun50
Estimates, Significant Accounting Policies and Balance Sheet Detials (Estimated aggregate amortization expense) (Details) $ in Millions | Dec. 31, 2015USD ($) |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |
2,016 | $ 195 |
2,017 | 195 |
2,018 | 195 |
2,019 | 193 |
2,020 | $ 193 |
Estimates, Significant Accoun51
Estimates, Significant Accounting Policies and Balance Sheet Detials (Changes in the carrying amount of goodwill) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Goodwill, Beginning Balance | $ 7,642 | $ 5,856 |
Goodwill acquired | 0 | 2,340 |
Impairment losses | (205) | (370) |
Goodwill, Written off Related to Sale of Business Unit | (2,018) | (184) |
Other | 9 | 0 |
Goodwill, Ending Balance | 5,428 | 7,642 |
Intrastate Transportation And Storage [Member] | ||
Goodwill, Beginning Balance | 10 | 10 |
Goodwill acquired | 0 | 0 |
Impairment losses | 0 | 0 |
Goodwill, Written off Related to Sale of Business Unit | 0 | 0 |
Other | 0 | 0 |
Goodwill, Ending Balance | 10 | 10 |
Interstate Transportation and Storage [Member] | ||
Goodwill, Beginning Balance | 1,011 | 1,195 |
Goodwill acquired | 0 | 0 |
Impairment losses | 99 | 0 |
Goodwill, Written off Related to Sale of Business Unit | 0 | (184) |
Other | 0 | 0 |
Goodwill, Ending Balance | 912 | 1,011 |
Midstream [Member] | ||
Goodwill, Beginning Balance | 767 | 686 |
Goodwill acquired | 0 | 451 |
Impairment losses | 0 | 370 |
Goodwill, Written off Related to Sale of Business Unit | 0 | 0 |
Other | (49) | 0 |
Goodwill, Ending Balance | 718 | 767 |
Liquids Transportation And Services [Member] | ||
Goodwill, Beginning Balance | 432 | 432 |
Goodwill acquired | 0 | 0 |
Impairment losses | 106 | 0 |
Goodwill, Written off Related to Sale of Business Unit | 0 | 0 |
Other | 0 | 0 |
Goodwill, Ending Balance | 326 | 432 |
Investment in Sunoco Logistics [Member] | ||
Goodwill, Beginning Balance | 1,358 | 1,346 |
Goodwill acquired | 0 | 12 |
Impairment losses | 0 | 0 |
Goodwill, Written off Related to Sale of Business Unit | 0 | 0 |
Other | 0 | 0 |
Goodwill, Ending Balance | 1,358 | 1,358 |
Retail Marketing [Member] | ||
Goodwill, Beginning Balance | 3,307 | 1,445 |
Goodwill acquired | $ 0 | 1,862 |
Impairment losses | 0 | |
Goodwill, Written off Related to Sale of Business Unit | $ (2,018) | 0 |
Other | 0 | 0 |
Goodwill, Ending Balance | 1,289 | 3,307 |
Other Segments [Member] | ||
Goodwill, Beginning Balance | 757 | 742 |
Goodwill acquired | 0 | 15 |
Impairment losses | 0 | 0 |
Goodwill, Written off Related to Sale of Business Unit | 0 | 0 |
Other | 58 | 0 |
Goodwill, Ending Balance | $ 815 | $ 757 |
Estimates, Significant Accoun52
Estimates, Significant Accounting Policies and Balance Sheet Detials (Asset Retirement Obligations) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Asset Retirement Obligation | $ 212 | $ 188 |
Interstate Transportation and Storage [Member] | ||
Asset Retirement Obligation | 58 | 60 |
Investment in Sunoco Logistics [Member] | ||
Asset Retirement Obligation | 88 | 41 |
Retail Marketing [Member] | ||
Asset Retirement Obligation | $ 66 | $ 87 |
Estimates, Significant Accoun53
Estimates, Significant Accounting Policies and Balance Sheet Detials (Accrued and Other Current Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Other Information [Abstract] | ||
Interest payable | $ 425 | $ 382 |
Customer advances and deposits | 95 | 103 |
Accrued capital expenditures | 743 | 673 |
Accrued wages and benefits | 218 | 233 |
Taxes payable other than income taxes | 76 | 236 |
Other | 386 | 373 |
Total accrued and other current liabilities | $ 1,943 | $ 2,000 |
Estimates, Significant Accoun54
Estimates, Significant Accounting Policies and Balance Sheet Detials (Assets and liabilities measured and recorded at fair value on a recurring basis) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value, Measurements, Recurring [Member] | ||
Interest rate derivatives, Assets | $ 3 | |
Price Risk Derivative Assets, at Fair Value | $ 448 | 745 |
Assets, Fair Value Disclosure, Recurring | 448 | 748 |
Interest rate derivatives, Liabilities | (171) | (155) |
Embedded derivatives in the ETP Preferred Units | (5) | (16) |
Price Risk Derivative Liabilities, at Fair Value | (350) | (578) |
Liabilities, Fair Value Disclosure, Recurring | (526) | (749) |
Forward Swaps [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 36 | |
Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 99 | 69 |
Price Risk Derivative Liabilities, at Fair Value | (89) | (32) |
Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 22 | 3 |
Price Risk Derivative Liabilities, at Fair Value | (22) | (4) |
Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 9 | 21 |
Price Risk Derivative Liabilities, at Fair Value | (7) | |
Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 3 | 4 |
Price Risk Derivative Liabilities, at Fair Value | (2) | (2) |
Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 9 | |
Price Risk Derivative Liabilities, at Fair Value | (5) | |
Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 4 | 1 |
Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 16 | 19 |
Price Risk Derivative Liabilities, at Fair Value | (16) | (18) |
Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 10 | 26 |
Price Risk Derivative Liabilities, at Fair Value | (12) | (25) |
Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 274 | 566 |
Price Risk Derivative Liabilities, at Fair Value | (203) | (490) |
Options - Puts [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Price Risk Derivative Liabilities, at Fair Value | (1) | |
Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring [Member] | ||
Interest rate derivatives, Assets | 0 | |
Price Risk Derivative Assets, at Fair Value | 414 | 632 |
Assets, Fair Value Disclosure, Recurring | 414 | 632 |
Interest rate derivatives, Liabilities | 0 | 0 |
Embedded derivatives in the ETP Preferred Units | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | (318) | (551) |
Liabilities, Fair Value Disclosure, Recurring | (318) | (551) |
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 99 | 46 |
Price Risk Derivative Liabilities, at Fair Value | (89) | (32) |
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 9 | 21 |
Price Risk Derivative Liabilities, at Fair Value | (7) | |
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 3 | 4 |
Price Risk Derivative Liabilities, at Fair Value | (2) | (2) |
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 9 | |
Price Risk Derivative Liabilities, at Fair Value | (5) | |
Fair Value, Inputs, Level 1 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 16 | 19 |
Price Risk Derivative Liabilities, at Fair Value | (16) | (18) |
Fair Value, Inputs, Level 1 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | 1 |
Price Risk Derivative Liabilities, at Fair Value | (2) | (2) |
Fair Value, Inputs, Level 1 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 274 | 541 |
Price Risk Derivative Liabilities, at Fair Value | (203) | (490) |
Fair Value, Inputs, Level 1 [Member] | Options - Puts [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Price Risk Derivative Liabilities, at Fair Value | (1) | |
Fair Value, Inputs, Level 1 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | ||
Interest rate derivatives, Assets | 3 | |
Price Risk Derivative Assets, at Fair Value | 34 | 113 |
Assets, Fair Value Disclosure, Recurring | 34 | 116 |
Interest rate derivatives, Liabilities | (171) | (155) |
Embedded derivatives in the ETP Preferred Units | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | (32) | (27) |
Liabilities, Fair Value Disclosure, Recurring | (203) | (182) |
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 36 | |
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 23 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 22 | 3 |
Price Risk Derivative Liabilities, at Fair Value | (22) | (4) |
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Inputs, Level 2 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 4 | 1 |
Fair Value, Inputs, Level 2 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 8 | 25 |
Price Risk Derivative Liabilities, at Fair Value | (10) | (23) |
Fair Value, Inputs, Level 2 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 25 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | Options - Puts [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Inputs, Level 2 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Fair Value, Inputs, Level 3 [Member] | ||
Liabilities, Fair Value Disclosure, Recurring | (5) | |
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | ||
Interest rate derivatives, Assets | 0 | |
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Assets, Fair Value Disclosure, Recurring | 0 | 0 |
Interest rate derivatives, Liabilities | 0 | 0 |
Embedded derivatives in the ETP Preferred Units | (5) | (16) |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Liabilities, Fair Value Disclosure, Recurring | (5) | (16) |
Fair Value, Inputs, Level 3 [Member] | Forward Swaps [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Fair Value, Inputs, Level 3 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Inputs, Level 3 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Inputs, Level 3 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | $ 0 |
Fair Value, Inputs, Level 3 [Member] | Options - Puts [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Inputs, Level 3 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | $ 0 |
Estimates, Significant Accoun55
Estimates, Significant Accounting Policies and Balance Sheet Detials (Unobservable Inputs and Reconciliation) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value, Measured on Recurring Basis, Gain (Loss) Included in Earnings | $ 11 | |
Fair Value Embedde Derivatives, Significant Unobservable Input, Credit Spread | 5.33% | |
Fair Value, Embedded Derivatives, Significant Unobservable Input, Volatility | 37.00% | |
Fair Value, Measurements, Recurring [Member] | ||
Liabilities, Fair Value Disclosure, Recurring | $ 526 | $ 749 |
Fair Value, Inputs, Level 3 [Member] | ||
Liabilities, Fair Value Disclosure, Recurring | 5 | |
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value | 16 | |
Liabilities, Fair Value Disclosure, Recurring | $ 5 | $ 16 |
Estimates, Significant Accoun56
Estimates, Significant Accounting Policies and Balance Sheet Detials (Costs and expenses) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Impairment losses | $ 205 | $ 370 | |
Retail Marketing [Member] | |||
Impairment losses | 0 | ||
Excise Taxes Collected | $ 1,850 | $ 2,460 | $ 2,220 |
Acquisitions and Divestitures57
Acquisitions and Divestitures (2015 Transactions) (Details) $ in Millions, gallons in Billions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Oct. 31, 2015USD ($)shares | Jul. 31, 2015USD ($)shares | Apr. 30, 2015USD ($)gallonsshares | Mar. 31, 2015USD ($)shares | Mar. 31, 2016USD ($)shares | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($)shares | Dec. 31, 2013USD ($)shares | Sep. 30, 2015shares | Jun. 30, 2015USD ($) | Dec. 31, 2011shares | |
Business Acquisition [Line Items] | ||||||||||||
Payments to Acquire Businesses, Gross | $ 382 | |||||||||||
Stock Repurchased During Period, Shares | shares | 0 | 0 | (400,000) | |||||||||
Goodwill | $ 5,428 | $ 7,642 | $ 5,856 | |||||||||
Intangible assets, net | $ 4,421 | $ 5,526 | ||||||||||
Partners' Capital Account, Units | shares | 505,600,000 | 355,500,000 | 333,800,000 | 301,500,000 | ||||||||
Class H Units | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Partners' Capital Account, Units | shares | 50,200,000 | |||||||||||
Allocation of Profits, Losses and Other by Sunoco, Percent | 50.05% | |||||||||||
Class B Units [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 9,400,000 | |||||||||||
Regency Merger [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Acquisition, Number Of Share Received In Exchange Of Each Share | shares | 0.4124 | |||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 172,200,000 | |||||||||||
Relinquishment of Incentive Distributions | $ 320 | |||||||||||
Dropdown of Sunoco LLC Interest [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage | 31.58% | |||||||||||
Business Combination, Consideration Transferred | $ 816 | |||||||||||
Gallons of motor fuel distributed | gallons | 5.3 | |||||||||||
Payments to Acquire Businesses, Gross | $ 775 | |||||||||||
Equity Issued in Business Combination, Fair Value Disclosure | $ 41 | |||||||||||
Dropdown of Susser [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Payments to Acquire Businesses, Gross | $ 970 | |||||||||||
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | $ 970 | |||||||||||
Sunoco LP Exchange [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Stock Repurchased During Period, Shares | shares | 21,000,000 | |||||||||||
IDR Subsidies | $ 35 | |||||||||||
Term of IDR Subsidy | 10 years | |||||||||||
Bakken Pipeline Transaction [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Combination, Consideration Transferred | $ 879 | |||||||||||
Partners' Capital Account, Units, Redeemed | shares | 30,800,000 | |||||||||||
Class I Distributions | $ 30 | 55 | ||||||||||
Bakken Pipeline Transaction [Member] | Class H Units | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Partners' Capital Account, Units, Redeemed | shares | 30,800,000 | |||||||||||
Allocation of Profits, Losses and Other by Sunoco, Percent | 90.05% | |||||||||||
Susser [Member] | Dropdown of Susser [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |||||||||||
Sunoco LP [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Goodwill | $ 1,810 | |||||||||||
Intangible assets, net | $ 982 | |||||||||||
Sunoco LP [Member] | Dropdown of Sunoco LLC Interest [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Combination, Consideration Transferred | $ 2,230 | |||||||||||
Payments to Acquire Businesses, Gross | $ 2,030 | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 5,700,000 | |||||||||||
Sunoco LP [Member] | Dropdown of Susser [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 22,000,000 | |||||||||||
Sunoco LP [Member] | Dropdown of Susser [Member] | Class A Units [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 79,308 | |||||||||||
Sunoco, LLC [Member] | Dropdown of Sunoco LLC Interest [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 68.42% | |||||||||||
Legacy Sunoco, Inc. [Member] | Dropdown of Sunoco LLC Interest [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |||||||||||
Parent Company [Member] | Bakken Pipeline Transaction [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Percent of total equity ownership of a subsidiary | 45.00% | |||||||||||
Sunoco GP [Member] | Sunoco LP Exchange [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |||||||||||
Bakken Holdings Company LLC [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 40.00% | |||||||||||
Dakota Access and ETCOC [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 75.00% | |||||||||||
ETP [Member] | Sunoco LP [Member] | Dropdown of Susser [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 10,900,000 | |||||||||||
ETP Subsidiaries [Member] | Regency Merger [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 15,500,000 | |||||||||||
ETP Series A Preferred Units [Member] | Regency Merger [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 1,900,000 | |||||||||||
Common Units | Sunoco LP [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Investment Owned, Balance, Shares | shares | 37,800,000 | |||||||||||
Relinquishment, Year 1 [Member] | Regency Merger [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Relinquishment of Incentive Distributions | 80 | |||||||||||
Relinquishment, Years 2 through 5 [Member] | Regency Merger [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Relinquishment of Incentive Distributions | $ 60 |
Acquisitions and Divestitures58
Acquisitions and Divestitures (2014 Narrative) (Details) $ / shares in Units, $ in Millions | Jan. 12, 2012shares | Oct. 31, 2015USD ($) | Oct. 31, 2014USD ($)shares | Aug. 31, 2014USD ($)shares | Mar. 21, 2014USD ($)$ / sharesshares | Feb. 28, 2014USD ($)shares | Dec. 31, 2013USD ($) | Apr. 30, 2013USD ($)shares | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($)shares | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($)shares | Dec. 31, 2013USD ($)shares | Apr. 30, 2015USD ($) | Oct. 01, 2014 | Aug. 29, 2014USD ($) | Jul. 01, 2014USD ($) | Jan. 10, 2014shares |
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | $ 5,825 | $ 6,601 | $ 11,540 | $ 10,326 | $ 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | $ 34,292 | $ 55,475 | $ 48,335 | |||||||||||||
Net income | $ 21 | $ 393 | $ 839 | $ 268 | (245) | $ 513 | $ 548 | $ 483 | 1,521 | 1,299 | 746 | |||||||||||||
Payments to Acquire Businesses, Gross | $ 382 | |||||||||||||||||||||||
Partners' Capital Account, Sale of Units | 1,428 | 1,382 | $ 1,611 | |||||||||||||||||||||
Goodwill, Written off Related to Sale of Business Unit | (2,018) | $ (184) | ||||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | $ 75 | |||||||||||||||||||||||
Debt instrument interest rate | 4.50% | 4.50% | ||||||||||||||||||||||
Number of Regency Common Units to be Issued in Acquisition Per Share | shares | 1.02 | |||||||||||||||||||||||
Susser Merger [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 1,800 | |||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 875 | |||||||||||||||||||||||
Number of Stores | 630 | |||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 15,800,000 | |||||||||||||||||||||||
MACS Transaction [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 768 | |||||||||||||||||||||||
Lake Charles LNG Transaction [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Partners' Capital Account, Units, Redeemed | shares | 18,700,000 | 51,800,000 | 18,700,000 | 0 | ||||||||||||||||||||
Goodwill, Written off Related to Sale of Business Unit | $ 184 | |||||||||||||||||||||||
Indefinite-lived Intangible Assets, Written off Related to Sale of Business Unit | $ 50 | |||||||||||||||||||||||
ETP Holdco Transaction (see Note 3) | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 1,400 | |||||||||||||||||||||||
ETP Holdco Transaction (see Note 3) | Common Units | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 49,500,000 | |||||||||||||||||||||||
Sunoco LP [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 556 | |||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 4,000,000 | 11,000,000 | ||||||||||||||||||||||
PVR Acquisition [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | $ 956 | |||||||||||||||||||||||
Net income | 166 | |||||||||||||||||||||||
Total current assets | 149 | |||||||||||||||||||||||
Property, plant and equipment | 2,716 | |||||||||||||||||||||||
Goodwill1 | 370 | |||||||||||||||||||||||
Intangible assets | 2,717 | |||||||||||||||||||||||
Other non-current assets | 18 | |||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 6,032 | |||||||||||||||||||||||
Total current liabilities | 168 | |||||||||||||||||||||||
Long-term debt, less current maturities | 1,788 | |||||||||||||||||||||||
Other non-current liabilities | 30 | |||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 2,085 | |||||||||||||||||||||||
Total consideration, net of cash received | 3,947 | |||||||||||||||||||||||
Eagle Rock Midstream Acquisition [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Revenues | $ 903 | |||||||||||||||||||||||
Net income | $ 30 | |||||||||||||||||||||||
Total current assets | $ 120 | |||||||||||||||||||||||
Property, plant and equipment | 1,295 | |||||||||||||||||||||||
Goodwill1 | 49 | |||||||||||||||||||||||
Other non-current assets | 4 | |||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 1,468 | |||||||||||||||||||||||
Total current liabilities | 116 | |||||||||||||||||||||||
Long-term debt, less current maturities | 499 | |||||||||||||||||||||||
Other non-current liabilities | 12 | |||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 627 | |||||||||||||||||||||||
Total consideration, net of cash received | $ 841 | |||||||||||||||||||||||
New England Gas Company [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Noncash or Part Noncash Divestiture, Amount of Consideration Received | $ 20 | |||||||||||||||||||||||
Sunoco LP [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Partners' Capital Account, Sale of Units | $ 405 | |||||||||||||||||||||||
Partners' Capital Account, Units, Sale of Units | shares | 9,100,000 | |||||||||||||||||||||||
AmeriGas [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 29,600,000 | |||||||||||||||||||||||
ETP [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Debt instrument interest rate | 6.50% | 6.50% | ||||||||||||||||||||||
Regency | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Senior Notes | $ 5,100 | |||||||||||||||||||||||
Regency | PVR Acquisition [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Payments to Acquire Businesses, Gross | 36 | |||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 5,700 | |||||||||||||||||||||||
Business Acquisition, Share Price | $ / shares | $ 27.82 | |||||||||||||||||||||||
Noncash or Part Noncash Divestiture, Amount of Consideration Received | $ 1,800 | |||||||||||||||||||||||
Regency | Eagle Rock Midstream Acquisition [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 1,300 | |||||||||||||||||||||||
Proceeds from Issuance of Common Stock | $ 400 | |||||||||||||||||||||||
Stock Issued During Period, Shares, Acquisitions | shares | 8,200,000 | |||||||||||||||||||||||
Susser [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Combination, Acquisition Related Costs | $ 25 | |||||||||||||||||||||||
Revenues | 2,320 | |||||||||||||||||||||||
Net income | $ 105 | |||||||||||||||||||||||
Incentive Distribution Rights | 100.00% | |||||||||||||||||||||||
Common Units | Regency | SUGS Contribution [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 31,400,000 | |||||||||||||||||||||||
Class F Units [Member] | Regency | SUGS Contribution [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 6,300,000 | |||||||||||||||||||||||
Susser Merger [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Total current assets | $ 446 | |||||||||||||||||||||||
Property, plant and equipment | 1,069 | |||||||||||||||||||||||
Goodwill1 | 1,734 | |||||||||||||||||||||||
Intangible assets | 611 | |||||||||||||||||||||||
Other non-current assets | 17 | |||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 3,877 | |||||||||||||||||||||||
Total current liabilities | 377 | |||||||||||||||||||||||
Long-term debt, less current maturities | 564 | |||||||||||||||||||||||
Deferred income taxes | 488 | |||||||||||||||||||||||
Other non-current liabilities | 39 | |||||||||||||||||||||||
Noncontrolling interest | 626 | |||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 2,094 | |||||||||||||||||||||||
Total consideration | 1,783 | |||||||||||||||||||||||
Cash received | 67 | |||||||||||||||||||||||
Total consideration, net of cash received | $ 1,716 | |||||||||||||||||||||||
Company-operated [Member] | MACS Transaction [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Number of Stores | 110 | |||||||||||||||||||||||
Dealer-operated [Member] | MACS Transaction [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Number of Stores | 200 | |||||||||||||||||||||||
Panhandle [Member] | ETP [Member] | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares | 2,200,000 | |||||||||||||||||||||||
8.375% Senior Notes due June 1, 2019 [Member] | Regency | ||||||||||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||||||||||
Senior Notes | $ 499 | $ 499 |
Acquisitions and Divestitures59
Acquisitions and Divestitures (2013 Narrative) (Details) - USD ($) shares in Millions, $ in Millions | Jan. 12, 2012 | Oct. 31, 2015 | Dec. 31, 2013 | Sep. 30, 2013 | Apr. 30, 2013 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2011 |
Business Acquisition [Line Items] | |||||||||||||||||
Payments to Acquire Businesses, Gross | $ 382 | ||||||||||||||||
Revenues | $ 5,825 | $ 6,601 | $ 11,540 | $ 10,326 | $ 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | $ 34,292 | $ 55,475 | $ 48,335 | ||||||
Net Income (Loss) Attributable to Parent | $ 1,398 | $ 1,336 | $ 456 | ||||||||||||||
Partners' Capital Account, Units | 333.8 | 505.6 | 355.5 | 505.6 | 355.5 | 333.8 | 301.5 | ||||||||||
ETP Holdco Transaction (see Note 3) | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Business Combination, Consideration Transferred | $ 1,400 | ||||||||||||||||
Estimated Closing Adjustments | $ 68 | ||||||||||||||||
Relinquishment of Rights of Incentive Distributions, Percentage | 50.00% | ||||||||||||||||
ETP Holdco Transaction (see Note 3) | Common Units | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 49.5 | ||||||||||||||||
AmeriGas [Member] | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 29.6 | ||||||||||||||||
Business Combination, Contingent Consideration, Liability | $ 1,550 | $ 1,550 | |||||||||||||||
ETP [Member] | ETP Holdco Transaction (see Note 3) | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Equity interest in Holdco | 100.00% | 100.00% | |||||||||||||||
Parent Company [Member] | ETP Holdco Transaction (see Note 3) | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Equity interest in Holdco | 60.00% | ||||||||||||||||
Sunoco [Member] | Class F Units [Member] | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Partners' Capital Account, Units | 40 | 40 | |||||||||||||||
Missouri Gas Energy [Member] | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Proceeds from Divestiture of Businesses | $ 975 | ||||||||||||||||
New England Gas Company [Member] | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Proceeds from Divestiture of Businesses | $ 40 | ||||||||||||||||
Noncash or Part Noncash Divestiture, Amount of Consideration Received | $ 20 | ||||||||||||||||
Common Units | Regency | SUGS Contribution [Member] | |||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 31.4 |
Acquisitions and Divestitures60
Acquisitions and Divestitures (Summary of Preliminary Assets And LiabilityAcquired) (Details) - USD ($) $ in Millions | Aug. 29, 2014 | Jul. 01, 2014 | Mar. 21, 2014 |
PVR Acquisition [Member] | |||
Business Acquisition [Line Items] | |||
Current assets | $ 149 | ||
Property, plant and equipment | 2,716 | ||
Goodwill | 370 | ||
Intangible Assets Acquired | 2,717 | ||
Investments in unconsolidated affiliates | 62 | ||
Other non-current assets | 18 | ||
Total assets acquired (excluding cash) | 6,032 | ||
Total current liabilities | 168 | ||
Long-term debt, less current maturities | 1,788 | ||
Business Combination, Purchase Price Allocation, Premium on Long Term Debt | 99 | ||
Other non-current liabilities | 30 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 2,085 | ||
Total consideration, net of cash received | $ 3,947 | ||
Eagle Rock Midstream Acquisition [Member] | |||
Business Acquisition [Line Items] | |||
Current assets | $ 120 | ||
Property, plant and equipment | 1,295 | ||
Goodwill | 49 | ||
Other non-current assets | 4 | ||
Total assets acquired (excluding cash) | 1,468 | ||
Total current liabilities | 116 | ||
Long-term debt, less current maturities | 499 | ||
Other non-current liabilities | 12 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 627 | ||
Total consideration, net of cash received | $ 841 | ||
Susser Merger [Member] | |||
Business Acquisition [Line Items] | |||
Current assets | $ 446 | ||
Property, plant and equipment | 1,069 | ||
Goodwill | 1,734 | ||
Intangible Assets Acquired | 611 | ||
Other non-current assets | 17 | ||
Total assets acquired (excluding cash) | 3,877 | ||
Total current liabilities | 377 | ||
Long-term debt, less current maturities | 564 | ||
Deferred income taxes | 488 | ||
Other non-current liabilities | 39 | ||
Noncontrolling interest | 626 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 2,094 | ||
Business Combination, Cost of Acquired Entity, Purchase Price | 1,783 | ||
Total consideration, net of cash received | 1,716 | ||
Cash received | $ 67 |
Acquisitions and Divestitures61
Acquisitions and Divestitures (Discontinued operations) (Details) - Distribution [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2013USD ($) | |
Disposal Group, Including Discontinued Operation, Revenue | $ 415 |
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax | $ 65 |
Investments in Unconsolidated62
Investments in Unconsolidated Affiliates (Narrative) (Details) - USD ($) shares in Millions, $ in Millions | Jan. 12, 2012 | Oct. 31, 2015 | Jul. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Schedule of Investments [Line Items] | ||||||
Payments to Acquire Businesses, Gross | $ 382 | |||||
Advances to and investments in unconsolidated affiliates | $ 5,003 | $ 3,760 | $ 4,050 | |||
Goodwill | $ 5,428 | $ 7,642 | 5,856 | |||
AmeriGas common units sold by ETP | (18.9) | (7.5) | ||||
Proceeds from the sale of AmeriGas common units | $ 0 | $ 814 | $ 346 | |||
FGT | ||||||
Schedule of Investments [Line Items] | ||||||
Percentage Ownership Operating Facility | 100.00% | |||||
AmeriGas [Member] | ||||||
Schedule of Investments [Line Items] | ||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 29.6 | |||||
Proceeds from the sale of AmeriGas common units | $ 814 | $ 346 | ||||
Investment Owned, Balance, Shares | 3.1 | |||||
Citrus [Member] | ||||||
Schedule of Investments [Line Items] | ||||||
Equity Method Investment, Ownership Percentage | 50.00% | |||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |||||
Advances to and investments in unconsolidated affiliates | $ 2,000 | |||||
Goodwill | $ 1,030 | |||||
FEP [Member] | ||||||
Schedule of Investments [Line Items] | ||||||
Equity Method Investment, Ownership Percentage | 50.00% | |||||
MEP [Member] | ||||||
Schedule of Investments [Line Items] | ||||||
Equity Method Investment, Ownership Percentage | 50.00% | |||||
RIGS Haynesville Partnership Co. [Member] | ||||||
Schedule of Investments [Line Items] | ||||||
Equity Method Investment, Ownership Percentage | 49.99% | |||||
Sunoco LP Exchange [Member] | Sunoco GP [Member] | ||||||
Schedule of Investments [Line Items] | ||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% |
Investments in Unconsolidated63
Investments in Unconsolidated Affiliates (Investments in Unconsolidated Affiliates) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Schedule of Equity Method Investments [Line Items] | |||
Advances to and investments in unconsolidated affiliates | $ 5,003 | $ 3,760 | $ 4,050 |
Citrus [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Advances to and investments in unconsolidated affiliates | 1,739 | 1,823 | |
Other Affiliates [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Advances to and investments in unconsolidated affiliates | 627 | 596 | |
Sunoco LP [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Advances to and investments in unconsolidated affiliates | 1,380 | 0 | |
RIGS Haynesville Partnership Co. [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Advances to and investments in unconsolidated affiliates | 402 | 422 | |
MEP [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Advances to and investments in unconsolidated affiliates | 660 | 695 | |
FEP [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Advances to and investments in unconsolidated affiliates | 115 | 130 | |
AmeriGas [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Advances to and investments in unconsolidated affiliates | $ 80 | $ 94 |
Investments in Unconsolidated64
Investments in Unconsolidated Affiliates (Summarized Financial Information) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Investments in and Advances to Affiliates [Line Items] | |||
Revenue | $ 20,961 | $ 4,925 | $ 4,695 |
Operating income | 1,620 | 1,071 | 1,197 |
Net income | 894 | 577 | $ 699 |
Current assets | 1,646 | 889 | |
Property, plant and equipment, net | 12,611 | 10,520 | |
Other assets | 5,485 | 2,687 | |
Total assets | 19,742 | 14,096 | |
Current liabilities | 1,517 | 1,983 | |
Non-current liabilities | 10,428 | 7,359 | |
Equity | 7,797 | 4,754 | |
Total liabilities and equity | $ 19,742 | $ 14,096 |
Net Income Per Limited Partne65
Net Income Per Limited Partner Unit (A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income from continuing operations | $ 1,521 | $ 1,235 | $ 713 |
Less: Income from continuing operations attributable to noncontrolling interest | 157 | 116 | 239 |
Less: Net income (loss) attributable to predecessor | (34) | (153) | 35 |
Income from continuing operations, net of noncontrolling interest | 1,398 | 1,272 | 439 |
General Partner’s interest in income from continuing operations | 1,064 | 513 | 505 |
Class H Unitholder’s interest in income from continuing operations | 258 | 217 | 0 |
Class I Unitholder’s interest in net income | 94 | 0 | 0 |
Common Unitholders’ interest in income (loss) from continuing operations | (18) | 542 | (66) |
Additional earnings allocated to General Partner | (5) | (4) | (2) |
Distributions on employee unit awards, net of allocation to General Partner | (16) | (13) | (10) |
Income (loss) from continuing operations available to Common Unitholders | (39) | 525 | (78) |
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities | (6) | 0 | 0 |
Net Income (Loss) Available to Common Stockholders, Diluted | $ (45) | $ 525 | $ (78) |
Weighted average Common Units – basic | 432.8 | 331.5 | 343.4 |
Basic income (loss) from continuing operations per Common Unit | $ (0.09) | $ 1.58 | $ (0.23) |
Dilutive effect of unvested Unit Awards | 0 | 1.3 | 0 |
Incremental Common Shares Attributable to Dilutive Effect of Conversion of Preferred Stock | 0.7 | 0 | 0 |
Weighted average Common Units – diluted | 433.5 | 332.8 | 343.4 |
Diluted income (loss) from continuing operations per Common Unit | $ (0.10) | $ 1.58 | $ (0.23) |
Basic income from discontinued operations per Common Unit | 0 | 0.19 | 0.05 |
Diluted income from discontinued operations per Common Unit | $ 0 | $ 0.19 | $ 0.05 |
Debt Obligations (Narrative) (D
Debt Obligations (Narrative) (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||
Aug. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Apr. 30, 2015USD ($) | Jan. 10, 2014 | Oct. 05, 2012USD ($) | ||
Unamortized Discounts, Premiums, Fair Value Adjustments and Deferred Debt Issuance Costs | $ (23) | |||||||||
Long-term Debt | $ 28,679 | $ 25,839 | ||||||||
Senior note interest rate | 4.50% | |||||||||
Proceeds from borrowings | $ 22,462 | 15,354 | $ 10,854 | |||||||
Repayments of Long-term Debt | 17,843 | 12,702 | $ 8,700 | |||||||
ETP Holdco Acquisition and SUGS Contribution | ||||||||||
Senior note principal amount | 465 | $ 965 | ||||||||
7.60% Senior Notes due February 1, 2024 | ||||||||||
Senior note interest rate | 7.60% | |||||||||
8.25% Senior Notes due November 14, 2029 | ||||||||||
Senior note interest rate | 8.25% | |||||||||
Regency | ||||||||||
Long-term Debt | [1] | 0 | 6,583 | |||||||
Senior note principal amount | $ 5,100 | |||||||||
Regency | 8.375% Senior Notes due June 1, 2019 [Member] | ||||||||||
Early Repayment of Senior Debt | $ 499 | |||||||||
Senior note interest rate | 8.375% | |||||||||
Regency | 4.5% Senior Notes due November 1, 2023 [Member] | ||||||||||
Senior note principal amount | $ 600 | |||||||||
Senior note interest rate | 4.50% | |||||||||
Regency | 5.75% Senior Notes due September 1, 2020 [Member] | ||||||||||
Senior note principal amount | $ 400 | |||||||||
Senior note interest rate | 5.75% | |||||||||
Regency | 8.375% Senior Notes due June 1, 2020 [Member] | ||||||||||
Senior note principal amount | $ 390 | |||||||||
Senior note interest rate | 8.375% | |||||||||
Redemption Premium | $ 40 | |||||||||
Regency | 6.5% Senior Notes due May 15, 2021 [Member] | ||||||||||
Senior note principal amount | $ 260 | |||||||||
Senior note interest rate | 6.50% | |||||||||
Redemption Premium | $ 24 | |||||||||
Regency | 6.5% Senior Notes, due July 15, 2021 [Member] | ||||||||||
Senior note principal amount | $ 500 | |||||||||
Senior note interest rate | 6.50% | |||||||||
Regency | 5.0% Senior Notes due October 1, 2022 [Member] | ||||||||||
Senior note principal amount | $ 700 | |||||||||
Senior note interest rate | 5.00% | |||||||||
Regency | 5.875% Senior Notes due March 1, 2022 [Member] | ||||||||||
Senior note principal amount | $ 900 | |||||||||
Senior note interest rate | 5.875% | |||||||||
Regency | Regency 4.50% Senior Notes Due 2023 [Member] | ||||||||||
Senior note principal amount | $ 600 | |||||||||
Senior note interest rate | 4.50% | |||||||||
Regency | 5.5% Senior Notes, due April 15, 2023 [Member] | ||||||||||
Senior note principal amount | $ 700 | |||||||||
Senior note interest rate | 5.50% | |||||||||
ETP [Member] | ||||||||||
Long-term Debt | $ 20,633 | 11,404 | ||||||||
Senior note interest rate | 6.50% | |||||||||
Proceeds from borrowings | $ 2,980 | $ 2,480 | ||||||||
Senior note maturity date | May 15, 2021 | |||||||||
Leverage Ratio Maximum | 5 | |||||||||
Maximum Leverage Ratio Permitted | 5.5 | |||||||||
ETP [Member] | 2.50% Senior Notes due June 2018 [Member] | ||||||||||
Senior note principal amount | $ 650 | |||||||||
Senior note interest rate | 2.50% | |||||||||
ETP [Member] | 4.15% Senior Notes due October 1, 2020 | ||||||||||
Senior note principal amount | $ 350 | |||||||||
Senior note interest rate | 4.15% | |||||||||
ETP [Member] | 4.75% Senior Notes due January 2026 [Member] | ||||||||||
Senior note principal amount | $ 1,000 | |||||||||
Senior note interest rate | 4.75% | |||||||||
ETP [Member] | 6.125% Senior Notes due December 2045 [Member] | ||||||||||
Senior note principal amount | $ 1,000 | |||||||||
Senior note interest rate | 6.125% | |||||||||
ETP [Member] | 4.05% Senior Notes due March 2025 [Member] | ||||||||||
Senior note principal amount | $ 1,000 | |||||||||
Senior note interest rate | 4.05% | |||||||||
ETP [Member] | 4.90% Senior Notes due March 2035 [Member] | ||||||||||
Senior note principal amount | $ 500 | |||||||||
Senior note interest rate | 4.90% | |||||||||
ETP [Member] | 5.15% Senior Notes due March 2045 [Member] | ||||||||||
Senior note principal amount | $ 1,000 | |||||||||
Senior note interest rate | 5.15% | |||||||||
Sunoco Logistics [Member] | ||||||||||
Long-term Debt | $ 5,590 | 4,234 | ||||||||
Maximum Consolidated EBITDA ratio | 5 | |||||||||
Adjusted EBITDA Ratio | 3.6 | |||||||||
Sunoco Logistics [Member] | Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | ||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 2,500 | |||||||||
Maximum revolving credit capacity | 3,250 | |||||||||
Sunoco LP [Member] | ||||||||||
Long-term Debt | [2] | $ 0 | 683 | |||||||
Acquisition Period [Member] | Sunoco Logistics [Member] | ||||||||||
Maximum Consolidated EBITDA ratio | 5.5 | |||||||||
ETP $3.75 billion Revolving Credit Facility due November 2019 | ||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 3,750 | |||||||||
4.40% Senior Notes due April 2021 [Member] | Sunoco Logistics [Member] | ||||||||||
Senior note principal amount | $ 600 | 0 | ||||||||
Senior note interest rate | 4.40% | |||||||||
Senior note maturity date | Apr. 1, 2021 | |||||||||
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member] | ||||||||||
Senior note principal amount | $ 500 | 500 | ||||||||
Senior note interest rate | 4.25% | |||||||||
Senior note maturity date | Apr. 1, 2024 | |||||||||
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member] | ||||||||||
Senior note principal amount | $ 700 | 700 | ||||||||
Senior note interest rate | 5.30% | |||||||||
Senior note maturity date | Apr. 1, 2044 | |||||||||
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member] | ||||||||||
Senior note principal amount | $ 350 | 350 | ||||||||
Senior note interest rate | 3.45% | |||||||||
Senior note maturity date | Jan. 15, 2023 | |||||||||
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member] | ||||||||||
Senior note principal amount | $ 350 | 350 | ||||||||
Senior note interest rate | 4.95% | |||||||||
Senior note maturity date | Jan. 15, 2043 | |||||||||
Junior Subordinated Debt [Member] | Variable Rate Portion of Debt [Member] | SUG [Member] | ||||||||||
Senior note principal amount | $ 54 | |||||||||
3.60% Senior Notes due February 1, 2023 | ETP [Member] | ||||||||||
Senior note principal amount | $ 800 | 800 | ||||||||
Senior note interest rate | 3.60% | |||||||||
Senior note maturity date | Feb. 1, 2023 | |||||||||
5.15% Senior Notes due February 1, 2043 | ETP [Member] | ||||||||||
Senior note principal amount | $ 450 | 450 | ||||||||
Senior note interest rate | 5.15% | |||||||||
Senior note maturity date | Feb. 1, 2043 | |||||||||
ETP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member] | ||||||||||
Senior note maturity date | Oct. 27, 2019 | |||||||||
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member] | ||||||||||
Senior note principal amount | $ 800 | 800 | ||||||||
Senior note interest rate | 5.35% | |||||||||
Senior note maturity date | May 15, 2045 | |||||||||
5.95% Senior Notes due December 2025 [Member] | Sunoco Logistics [Member] | ||||||||||
Senior note principal amount | $ 400 | 0 | ||||||||
Senior note interest rate | 5.95% | |||||||||
Senior note maturity date | Dec. 1, 2025 | |||||||||
ETP Credit Facility due November 2019 [Member] | ETP [Member] | ||||||||||
Revolving credit facility balance outstanding | $ 1,362 | $ 570 | ||||||||
Amount available for future borrowings under the revolving credit facitlity | 2,240 | |||||||||
Letters of credit outstanding, amount | $ 145 | |||||||||
Weighted average interest rate on the total amount outstanding | 1.86% | |||||||||
[1] | (4) As discussed below, the Regency senior notes were redeemed and/or assumed by the Partnership. On April 30, 2015, in connection with the Regency Merger, the Regency Revolving Credit Facility was paid off in full and terminated. | |||||||||
[2] | (3) In connection with ETE’s acquisition of Sunoco GP, the general partner of Sunoco LP, on July 1, 2015, ETP deconsolidated Sunoco LP. |
Debt Obligations (Debt Instrume
Debt Obligations (Debt Instruments) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Apr. 30, 2015 | Dec. 31, 2014 | ||
Long-term Debt | $ 28,679 | $ 25,839 | ||
Other | 32 | 223 | ||
Less: current maturities | (126) | (1,008) | ||
Long-term debt, less current maturities | $ 28,553 | 24,831 | ||
Debt instrument interest rate | 4.50% | |||
ETP [Member] | ||||
Unamortized premiums, discounts and fair value adjustments, net | $ (21) | (1) | ||
Deferred Finance Costs, Noncurrent, Net | (147) | (55) | ||
Long-term Debt | $ 20,633 | 11,404 | ||
Debt instrument interest rate | 6.50% | |||
Debt instrument maturity date | May 15, 2021 | |||
Transwestern [Member] | ||||
Unamortized premiums, discounts and fair value adjustments, net | $ (1) | (1) | ||
Deferred Finance Costs, Noncurrent, Net | (2) | (3) | ||
Long-term Debt | 779 | 778 | ||
Panhandle [Member] | ||||
Unamortized premiums, discounts and fair value adjustments, net | 75 | 99 | ||
Long-term Debt | 1,160 | 1,184 | ||
Sunoco [Member] | ||||
Unamortized premiums, discounts and fair value adjustments, net | 20 | 35 | ||
Long-term Debt | 485 | 750 | ||
Sunoco Logistics [Member] | ||||
Unamortized premiums, discounts and fair value adjustments, net | 85 | 100 | ||
Deferred Finance Costs, Noncurrent, Net | (32) | (26) | ||
Long-term Debt | 5,590 | 4,234 | ||
Sunoco LP [Member] | ||||
Long-term Debt | [1] | 0 | 683 | |
Regency | ||||
Senior Notes | $ 5,100 | |||
Deferred Finance Costs, Noncurrent, Net | 58 | |||
Long-term Debt | [2] | 0 | 6,583 | |
5.95% Senior Notes due February 1, 2015 | ETP [Member] | ||||
Senior Notes | $ 0 | 750 | ||
Debt instrument interest rate | 5.95% | |||
Debt instrument maturity date | Feb. 1, 2015 | |||
6.125% Senior Notes due February 15, 2017 | ETP [Member] | ||||
Senior Notes | $ 400 | 400 | ||
Debt instrument interest rate | 6.125% | |||
Debt instrument maturity date | Feb. 15, 2017 | |||
2.50% Senior Notes due June 2018 [Member] | ETP [Member] | ||||
Senior Notes | $ 650 | 0 | ||
Debt instrument interest rate | 2.50% | |||
Debt instrument maturity date | Jun. 15, 2018 | |||
6.7% Senior Notes due July 1, 2018 | ETP [Member] | ||||
Senior Notes | $ 600 | 600 | ||
Debt instrument interest rate | 6.70% | |||
Debt instrument maturity date | Jul. 1, 2018 | |||
9.7% Senior Notes due March 15, 2019 | ETP [Member] | ||||
Senior Notes | $ 400 | 400 | ||
Debt instrument interest rate | 9.70% | |||
Debt instrument maturity date | Mar. 15, 2019 | |||
9.0% Senior Notes due April 15, 2019 | ETP [Member] | ||||
Senior Notes | $ 450 | 450 | ||
Debt instrument interest rate | 9.00% | |||
Debt instrument maturity date | Apr. 15, 2019 | |||
4.15% Senior Notes due October 1, 2020 | ETP [Member] | ||||
Senior Notes | $ 1,050 | 700 | ||
Debt instrument interest rate | 4.15% | |||
Debt instrument maturity date | Oct. 1, 2020 | |||
4.65% Senior Notes due June 1, 2021 | ETP [Member] | ||||
Senior Notes | $ 800 | 800 | ||
Debt instrument interest rate | 4.65% | |||
Debt instrument maturity date | Jun. 1, 2021 | |||
5.20% Senior Notes due February 1, 2022 | ETP [Member] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Debt instrument interest rate | 5.20% | |||
Debt instrument maturity date | Feb. 1, 2022 | |||
3.60% Senior Notes due February 1, 2023 | ETP [Member] | ||||
Senior Notes | $ 800 | 800 | ||
Debt instrument interest rate | 3.60% | |||
Debt instrument maturity date | Feb. 1, 2023 | |||
4.9% Senior Notes due February 1, 2024 | ETP [Member] | ||||
Senior Notes | $ 350 | 350 | ||
Debt instrument interest rate | 4.90% | |||
Debt instrument maturity date | Feb. 1, 2024 | |||
7.60% Senior Notes due February 1, 2024 | ETP [Member] | ||||
Senior Notes | $ 277 | 277 | ||
Debt instrument interest rate | 7.60% | |||
Debt instrument maturity date | Feb. 1, 2024 | |||
7.60% Senior Notes due February 1, 2024 | Panhandle [Member] | ||||
Senior Notes | $ 82 | 82 | ||
4.05% Senior Notes due March 2025 [Member] | ETP [Member] | ||||
Senior Notes | $ 1,000 | 0 | ||
Debt instrument interest rate | 4.05% | |||
Debt instrument maturity date | Mar. 15, 2025 | |||
4.75% Senior Notes due January 2026 [Member] | ETP [Member] | ||||
Senior Notes | $ 1,000 | 0 | ||
Debt instrument interest rate | 4.75% | |||
Debt instrument maturity date | Jan. 15, 2026 | |||
8.25% Senior Notes due November 14, 2029 | ETP [Member] | ||||
Senior Notes | $ 267 | 267 | ||
Debt instrument interest rate | 8.25% | |||
Debt instrument maturity date | Nov. 15, 2029 | |||
8.25% Senior Notes due November 14, 2029 | Panhandle [Member] | ||||
Senior Notes | $ 33 | 33 | ||
4.90% Senior Notes due March 2035 [Member] | ETP [Member] | ||||
Senior Notes | $ 500 | 0 | ||
Debt instrument interest rate | 4.90% | |||
Debt instrument maturity date | Mar. 15, 2035 | |||
6.625% Senior Notes due October 15, 2036 | ETP [Member] | ||||
Senior Notes | $ 400 | 400 | ||
Debt instrument interest rate | 6.625% | |||
Debt instrument maturity date | Oct. 15, 2036 | |||
7.5% Senior Notes due July 1, 2038 | ETP [Member] | ||||
Senior Notes | $ 550 | 550 | ||
Debt instrument interest rate | 7.50% | |||
Debt instrument maturity date | Jul. 1, 2038 | |||
6.05% Senior Notes due June 1, 2041 | ETP [Member] | ||||
Senior Notes | $ 700 | 700 | ||
Debt instrument interest rate | 6.05% | |||
Debt instrument maturity date | Jun. 1, 2041 | |||
6.50% Senior Notes due February 1, 2042 | ETP [Member] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Debt instrument interest rate | 6.50% | |||
Debt instrument maturity date | Feb. 1, 2042 | |||
5.15% Senior Notes due February 1, 2043 | ETP [Member] | ||||
Senior Notes | $ 450 | 450 | ||
Debt instrument interest rate | 5.15% | |||
Debt instrument maturity date | Feb. 1, 2043 | |||
5.95% Senior Notes due October 1, 2043 | ETP [Member] | ||||
Senior Notes | $ 450 | 450 | ||
Debt instrument interest rate | 5.95% | |||
Debt instrument maturity date | Oct. 1, 2043 | |||
5.15% Senior Notes due March 2045 [Member] | ETP [Member] | ||||
Senior Notes | $ 1,000 | 0 | ||
Debt instrument interest rate | 5.15% | |||
Debt instrument maturity date | Mar. 15, 2045 | |||
6.125% Senior Notes due December 2045 [Member] | ETP [Member] | ||||
Senior Notes | $ 1,000 | 0 | ||
Debt instrument interest rate | 6.125% | |||
Debt instrument maturity date | Dec. 15, 2045 | |||
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member] | ||||
Junior Subordinated Notes | $ 545 | 546 | ||
Debt instrument maturity date | Nov. 1, 2066 | |||
Debt Instrument, Interest Rate, Effective Percentage | 3.645% | |||
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member] | ||||
Junior Subordinated Notes | $ 54 | 54 | ||
Debt instrument maturity date | Nov. 1, 2066 | |||
ETP Credit Facility due November 2019 [Member] | ETP [Member] | ||||
Revolving credit facilities | $ 1,362 | 570 | ||
ETP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member] | ||||
Debt instrument maturity date | Oct. 27, 2019 | |||
5.54% Senior Notes due November 17, 2016 | Transwestern [Member] | ||||
Senior Notes | $ 125 | 125 | ||
Debt instrument interest rate | 5.54% | |||
Debt instrument maturity date | Nov. 17, 2016 | |||
5.64% Senior Notes due May 24, 2017 | Transwestern [Member] | ||||
Senior Notes | $ 82 | 82 | ||
Debt instrument interest rate | 5.64% | |||
Debt instrument maturity date | May 24, 2017 | |||
5.36% Senior Notes due December 9, 2020 | Transwestern [Member] | ||||
Senior Notes | $ 175 | 175 | ||
Debt instrument interest rate | 5.36% | |||
Debt instrument maturity date | Dec. 9, 2020 | |||
5.89% Senior Notes due May 24, 2022 | Transwestern [Member] | ||||
Senior Notes | $ 150 | 150 | ||
Debt instrument interest rate | 5.89% | |||
Debt instrument maturity date | May 24, 2022 | |||
5.66% Senior Notes due December 9, 2024 | Transwestern [Member] | ||||
Senior Notes | $ 175 | 175 | ||
Debt instrument interest rate | 5.66% | |||
Debt instrument maturity date | Dec. 9, 2024 | |||
6.16% Senior Notes due May 24, 2037 | Transwestern [Member] | ||||
Senior Notes | $ 75 | 75 | ||
Debt instrument interest rate | 6.16% | |||
Debt instrument maturity date | May 24, 2037 | |||
6.20% Senior Notes due November 1, 2017 | Panhandle [Member] | ||||
Senior Notes | $ 300 | 300 | ||
Debt instrument interest rate | 6.20% | |||
Debt instrument maturity date | Nov. 1, 2017 | |||
7.00% Senior Notes due June 15, 2018 | Panhandle [Member] | ||||
Senior Notes | $ 400 | 400 | ||
Debt instrument interest rate | 7.00% | |||
Debt instrument maturity date | Jun. 15, 2018 | |||
8.125% Senior Notes due June 1, 2019 | Panhandle [Member] | ||||
Senior Notes | $ 150 | 150 | ||
Debt instrument interest rate | 8.125% | |||
Debt instrument maturity date | Jun. 1, 2019 | |||
7.00% Senior Notes due July 15, 2029 | Panhandle [Member] | ||||
Senior Notes | $ 66 | 66 | ||
Debt instrument interest rate | 7.00% | |||
Debt instrument maturity date | Jul. 15, 2029 | |||
9.625% Senior Notes due April 15, 2015 | Sunoco [Member] | ||||
Senior Notes | $ 0 | 250 | ||
Debt instrument interest rate | 9.625% | |||
Debt instrument maturity date | Apr. 15, 2015 | |||
5.75% Senior Notes due January 15, 2017 | Sunoco [Member] | ||||
Senior Notes | $ 400 | 400 | ||
Debt instrument interest rate | 5.75% | |||
Debt instrument maturity date | Jan. 15, 2017 | |||
9.00% Debentures due November 1, 2024 | Sunoco [Member] | ||||
Subordinated Debt | $ 65 | 65 | ||
Debt instrument interest rate | 9.00% | |||
Debt instrument maturity date | Nov. 1, 2024 | |||
6.125% Senior Notes due May 15, 2016 (1) | Sunoco Logistics [Member] | ||||
Senior Notes | [3] | $ 175 | 175 | |
Debt instrument interest rate | 6.125% | |||
Debt instrument maturity date | May 15, 2016 | |||
5.50% Senior Notes due February 15, 2020 | Sunoco Logistics [Member] | ||||
Senior Notes | $ 250 | 250 | ||
Debt instrument interest rate | 5.50% | |||
Debt instrument maturity date | Feb. 15, 2020 | |||
4.40% Senior Notes due April 2021 [Member] | Sunoco Logistics [Member] | ||||
Senior Notes | $ 600 | 0 | ||
Debt instrument interest rate | 4.40% | |||
Debt instrument maturity date | Apr. 1, 2021 | |||
4.65% Senior Notes due February 15, 2022 | Sunoco Logistics [Member] | ||||
Senior Notes | $ 300 | 300 | ||
Debt instrument interest rate | 4.65% | |||
Debt instrument maturity date | Feb. 15, 2022 | |||
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member] | ||||
Senior Notes | $ 350 | 350 | ||
Debt instrument interest rate | 3.45% | |||
Debt instrument maturity date | Jan. 15, 2023 | |||
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member] | ||||
Senior Notes | $ 500 | 500 | ||
Debt instrument interest rate | 4.25% | |||
Debt instrument maturity date | Apr. 1, 2024 | |||
5.95% Senior Notes due December 2025 [Member] | Sunoco Logistics [Member] | ||||
Senior Notes | $ 400 | 0 | ||
Debt instrument interest rate | 5.95% | |||
Debt instrument maturity date | Dec. 1, 2025 | |||
6.85% Senior Notes due February 15, 2040 | Sunoco Logistics [Member] | ||||
Senior Notes | $ 250 | 250 | ||
Debt instrument interest rate | 6.85% | |||
Debt instrument maturity date | Feb. 15, 2040 | |||
6.10% Senior Notes due February 15, 2042 | Sunoco Logistics [Member] | ||||
Senior Notes | $ 300 | 300 | ||
Debt instrument interest rate | 6.10% | |||
Debt instrument maturity date | Feb. 15, 2042 | |||
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member] | ||||
Senior Notes | $ 350 | 350 | ||
Debt instrument interest rate | 4.95% | |||
Debt instrument maturity date | Jan. 15, 2043 | |||
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member] | ||||
Senior Notes | $ 700 | 700 | ||
Debt instrument interest rate | 5.30% | |||
Debt instrument maturity date | Apr. 1, 2044 | |||
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member] | ||||
Senior Notes | $ 800 | 800 | ||
Debt instrument interest rate | 5.35% | |||
Debt instrument maturity date | May 15, 2045 | |||
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015 (2) | Sunoco Logistics [Member] | ||||
Revolving credit facilities | [4] | $ 0 | 35 | |
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | Sunoco Logistics [Member] | ||||
Revolving credit facilities | 562 | 150 | ||
8.375% Senior Notes due June 1, 2019 [Member] | Regency | ||||
Senior Notes | 499 | |||
5.75% Senior Notes due September 1, 2020 [Member] | ETP [Member] | ||||
Senior Notes | $ 400 | 0 | ||
Debt instrument interest rate | 5.75% | |||
Debt instrument maturity date | Sep. 1, 2020 | |||
6.5% Senior Notes due May 15, 2021 [Member] | ETP [Member] | ||||
Senior Notes | $ 500 | 0 | ||
5.875% Senior Notes due March 1, 2022 [Member] | ETP [Member] | ||||
Senior Notes | $ 900 | 0 | ||
Debt instrument interest rate | 5.875% | |||
Debt instrument maturity date | Mar. 1, 2022 | |||
5.0% Senior Notes due October 1, 2022 [Member] | ETP [Member] | ||||
Senior Notes | $ 700 | 0 | ||
Debt instrument interest rate | 5.00% | |||
Debt instrument maturity date | Oct. 1, 2022 | |||
5.5% Senior Notes, due April 15, 2023 [Member] | ETP [Member] | ||||
Senior Notes | $ 700 | 0 | ||
Debt instrument interest rate | 5.50% | |||
Debt instrument maturity date | Apr. 15, 2023 | |||
4.5% Senior Notes due November 1, 2023 [Member] | ETP [Member] | ||||
Senior Notes | $ 600 | $ 0 | ||
Debt instrument interest rate | 4.50% | |||
Debt instrument maturity date | Nov. 1, 2023 | |||
[1] | (3) In connection with ETE’s acquisition of Sunoco GP, the general partner of Sunoco LP, on July 1, 2015, ETP deconsolidated Sunoco LP. | |||
[2] | (4) As discussed below, the Regency senior notes were redeemed and/or assumed by the Partnership. On April 30, 2015, in connection with the Regency Merger, the Regency Revolving Credit Facility was paid off in full and terminated. | |||
[3] | (1) Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of December 31, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. | |||
[4] | (2) Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility matured in April 2015 and was repaid with borrowings from the Sunoco Logistics $2.50 billion Revolving Credit Facility. |
Debt Obligations Debt Instrumen
Debt Obligations Debt Instruments (Parenthetical) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Senior note interest rate | 4.50% | |
ETP [Member] | ||
Senior note interest rate | 6.50% | |
Debt instrument maturity date | May 15, 2021 | |
Deferred Finance Costs, Noncurrent, Net | $ (147) | $ (55) |
Transwestern [Member] | ||
Deferred Finance Costs, Noncurrent, Net | (2) | (3) |
Sunoco Logistics [Member] | ||
Deferred Finance Costs, Noncurrent, Net | $ (32) | (26) |
Regency [Member] | ||
Deferred Finance Costs, Noncurrent, Net | $ 58 | |
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member] | ||
Senior note interest rate | 4.25% | |
Debt instrument maturity date | Apr. 1, 2024 | |
5.95% Senior Notes due December 2025 [Member] | Sunoco Logistics [Member] | ||
Senior note interest rate | 5.95% | |
Debt instrument maturity date | Dec. 1, 2025 | |
6.85% Senior Notes due February 15, 2040 | Sunoco Logistics [Member] | ||
Senior note interest rate | 6.85% | |
Debt instrument maturity date | Feb. 15, 2040 | |
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member] | ||
Senior note interest rate | 5.30% | |
Debt instrument maturity date | Apr. 1, 2044 | |
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member] | ||
Senior note interest rate | 5.35% | |
Debt instrument maturity date | May 15, 2045 | |
5.95% Senior Notes due February 1, 2015 | ETP [Member] | ||
Senior note interest rate | 5.95% | |
Debt instrument maturity date | Feb. 1, 2015 | |
6.125% Senior Notes due February 15, 2017 | ETP [Member] | ||
Senior note interest rate | 6.125% | |
Debt instrument maturity date | Feb. 15, 2017 | |
2.50% Senior Notes due June 2018 [Member] | ETP [Member] | ||
Senior note interest rate | 2.50% | |
Debt instrument maturity date | Jun. 15, 2018 | |
6.7% Senior Notes due July 1, 2018 | ETP [Member] | ||
Senior note interest rate | 6.70% | |
Debt instrument maturity date | Jul. 1, 2018 | |
9.7% Senior Notes due March 15, 2019 | ETP [Member] | ||
Senior note interest rate | 9.70% | |
Debt instrument maturity date | Mar. 15, 2019 | |
9.0% Senior Notes due April 15, 2019 | ETP [Member] | ||
Senior note interest rate | 9.00% | |
Debt instrument maturity date | Apr. 15, 2019 | |
5.75% Senior Notes due September 1, 2020 [Member] | ETP [Member] | ||
Senior note interest rate | 5.75% | |
Debt instrument maturity date | Sep. 1, 2020 | |
4.15% Senior Notes due October 1, 2020 [Member] | ETP [Member] | ||
Senior note interest rate | 4.15% | |
Debt instrument maturity date | Oct. 1, 2020 | |
4.65% Senior Notes due June 1, 2021 | ETP [Member] | ||
Senior note interest rate | 4.65% | |
Debt instrument maturity date | Jun. 1, 2021 | |
5.20% Senior Notes due February 1, 2022 | ETP [Member] | ||
Senior note interest rate | 5.20% | |
Debt instrument maturity date | Feb. 1, 2022 | |
5.875% Senior Notes due March 1, 2022 [Member] | ETP [Member] | ||
Senior note interest rate | 5.875% | |
Debt instrument maturity date | Mar. 1, 2022 | |
5.0% Senior Notes due October 1, 2022 [Member] | ETP [Member] | ||
Senior note interest rate | 5.00% | |
Debt instrument maturity date | Oct. 1, 2022 | |
3.60% Senior Notes due February 1, 2023 | ETP [Member] | ||
Senior note interest rate | 3.60% | |
Debt instrument maturity date | Feb. 1, 2023 | |
5.5% Senior Notes, due April 15, 2023 [Member] | ETP [Member] | ||
Senior note interest rate | 5.50% | |
Debt instrument maturity date | Apr. 15, 2023 | |
4.5% Senior Notes due November 1, 2023 [Member] | ETP [Member] | ||
Senior note interest rate | 4.50% | |
Debt instrument maturity date | Nov. 1, 2023 | |
4.9% Senior Notes due February 1, 2024 | ETP [Member] | ||
Senior note interest rate | 4.90% | |
Debt instrument maturity date | Feb. 1, 2024 | |
7.60% Senior Notes due February 1, 2024 | ETP [Member] | ||
Senior note interest rate | 7.60% | |
Debt instrument maturity date | Feb. 1, 2024 | |
7.60% Senior Notes due February 1, 2024 | Southern Union [Member] | ||
Senior note interest rate | 7.60% | |
Debt instrument maturity date | Feb. 1, 2024 | |
4.05% Senior Notes due March 2025 [Member] | ETP [Member] | ||
Senior note interest rate | 4.05% | |
Debt instrument maturity date | Mar. 15, 2025 | |
4.75% Senior Notes due January 2026 [Member] | ETP [Member] | ||
Senior note interest rate | 4.75% | |
Debt instrument maturity date | Jan. 15, 2026 | |
8.25% Senior Notes due November 14, 2029 | ETP [Member] | ||
Senior note interest rate | 8.25% | |
Debt instrument maturity date | Nov. 15, 2029 | |
8.25% Senior Notes due November 14, 2029 | Southern Union [Member] | ||
Senior note interest rate | 8.25% | |
Debt instrument maturity date | Nov. 14, 2029 | |
6.625% Senior Notes due October 15, 2036 | ETP [Member] | ||
Senior note interest rate | 6.625% | |
Debt instrument maturity date | Oct. 15, 2036 | |
4.90% Senior Notes due March 2035 [Member] | ETP [Member] | ||
Senior note interest rate | 4.90% | |
Debt instrument maturity date | Mar. 15, 2035 | |
7.5% Senior Notes due July 1, 2038 | ETP [Member] | ||
Senior note interest rate | 7.50% | |
Debt instrument maturity date | Jul. 1, 2038 | |
6.05% Senior Notes due June 1, 2041 | ETP [Member] | ||
Senior note interest rate | 6.05% | |
Debt instrument maturity date | Jun. 1, 2041 | |
6.50% Senior Notes due February 1, 2042 | ETP [Member] | ||
Senior note interest rate | 6.50% | |
Debt instrument maturity date | Feb. 1, 2042 | |
5.15% Senior Notes due February 1, 2043 | ETP [Member] | ||
Senior note interest rate | 5.15% | |
Debt instrument maturity date | Feb. 1, 2043 | |
5.95% Senior Notes due October 1, 2043 | ETP [Member] | ||
Senior note interest rate | 5.95% | |
Debt instrument maturity date | Oct. 1, 2043 | |
5.15% Senior Notes due March 2045 [Member] | ETP [Member] | ||
Senior note interest rate | 5.15% | |
Debt instrument maturity date | Mar. 15, 2045 | |
6.125% Senior Notes due December 2045 [Member] | ETP [Member] | ||
Senior note interest rate | 6.125% | |
Debt instrument maturity date | Dec. 15, 2045 | |
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member] | ||
Debt instrument maturity date | Nov. 1, 2066 | |
Debt Instrument, Interest Rate, Effective Percentage | 3.645% | |
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member] | ||
Debt instrument maturity date | Nov. 1, 2066 | |
ETP Credit Facility due November 2019 [Member] | ETP [Member] | ||
Weighted average interest rate on the total amount outstanding | 1.86% | |
ETP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member] | ||
Debt instrument maturity date | Oct. 27, 2019 | |
5.54% Senior Notes due November 17, 2016 | Transwestern [Member] | ||
Senior note interest rate | 5.54% | |
Debt instrument maturity date | Nov. 17, 2016 | |
5.64% Senior Notes due May 24, 2017 | Transwestern [Member] | ||
Senior note interest rate | 5.64% | |
Debt instrument maturity date | May 24, 2017 | |
5.36% Senior Notes due December 9, 2020 | Transwestern [Member] | ||
Senior note interest rate | 5.36% | |
Debt instrument maturity date | Dec. 9, 2020 | |
5.89% Senior Notes due May 24, 2022 | Transwestern [Member] | ||
Senior note interest rate | 5.89% | |
Debt instrument maturity date | May 24, 2022 | |
5.66% Senior Notes due December 9, 2024 | Transwestern [Member] | ||
Senior note interest rate | 5.66% | |
Debt instrument maturity date | Dec. 9, 2024 | |
6.16% Senior Notes due May 24, 2037 | Transwestern [Member] | ||
Senior note interest rate | 6.16% | |
Debt instrument maturity date | May 24, 2037 | |
6.20% Senior Notes due November 1, 2017 | Panhandle [Member] | ||
Senior note interest rate | 6.20% | |
Debt instrument maturity date | Nov. 1, 2017 | |
7.00% Senior Notes due June 15, 2018 | Panhandle [Member] | ||
Senior note interest rate | 7.00% | |
Debt instrument maturity date | Jun. 15, 2018 | |
8.125% Senior Notes due June 1, 2019 | Panhandle [Member] | ||
Senior note interest rate | 8.125% | |
Debt instrument maturity date | Jun. 1, 2019 | |
7.00% Senior Notes due July 15, 2029 | Panhandle [Member] | ||
Senior note interest rate | 7.00% | |
Debt instrument maturity date | Jul. 15, 2029 | |
9.625% Senior Notes due April 15, 2015 | Sunoco [Member] | ||
Senior note interest rate | 9.625% | |
Debt instrument maturity date | Apr. 15, 2015 | |
6.125% Senior Notes due May 15, 2016 (1) | Sunoco Logistics [Member] | ||
Senior note interest rate | 6.125% | |
Debt instrument maturity date | May 15, 2016 | |
5.50% Senior Notes due February 15, 2020 | Sunoco Logistics [Member] | ||
Senior note interest rate | 5.50% | |
Debt instrument maturity date | Feb. 15, 2020 | |
4.40% Senior Notes due April 2021 [Member] | Sunoco Logistics [Member] | ||
Senior note interest rate | 4.40% | |
Debt instrument maturity date | Apr. 1, 2021 | |
4.65% Senior Notes due February 15, 2022 | Sunoco Logistics [Member] | ||
Senior note interest rate | 4.65% | |
Debt instrument maturity date | Feb. 15, 2022 | |
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member] | ||
Senior note interest rate | 3.45% | |
Debt instrument maturity date | Jan. 15, 2023 | |
6.10% Senior Notes due February 15, 2042 | Sunoco Logistics [Member] | ||
Senior note interest rate | 6.10% | |
Debt instrument maturity date | Feb. 15, 2042 | |
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member] | ||
Senior note interest rate | 4.95% | |
Debt instrument maturity date | Jan. 15, 2043 | |
5.75% Senior Notes due January 15, 2017 | Sunoco [Member] | ||
Senior note interest rate | 5.75% | |
Debt instrument maturity date | Jan. 15, 2017 | |
9.00% Debentures due November 1, 2024 | Sunoco [Member] | ||
Senior note interest rate | 9.00% | |
Debt instrument maturity date | Nov. 1, 2024 |
Debt Obligations (Future maturi
Debt Obligations (Future maturities of long-term debt) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
2,015 | $ 301 | |
2,016 | 1,182 | |
2,017 | 1,650 | |
2,018 | 2,362 | |
2,019 | 2,937 | |
Thereafter | 20,270 | |
Long-term Debt | 28,679 | $ 25,839 |
Excluding unamortized premiums and fair value adjustments [Member] | ||
Long-term Debt | $ 28,702 |
Series A Preferred Units (Detai
Series A Preferred Units (Details) shares in Millions | 9 Months Ended | |
Sep. 30, 2015shares | Apr. 30, 2015USD ($)$ / commonunitshares | |
Preferred Units Redemption Amount | $ 35,000,000 | |
Preferred Units Quarterly Cash Distribution Per Unit | $ / commonunit | 0.445 | |
Preferrred Units Issued Stated Price | $ 18.30 | |
Conversion Price of Preferred Units | $ 44.37 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares | 0.9 | |
Regency Merger [Member] | ||
Preferred Units, Issued | shares | 1.9 |
Equity (Narrative) (Details)
Equity (Narrative) (Details) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||
Apr. 30, 2015USD ($)shares | Mar. 31, 2015USD ($)shares | Apr. 30, 2013USD ($)shares | Dec. 31, 2014USD ($)shares | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($)shares | Dec. 31, 2013USD ($)shares | Sep. 30, 2015 | Oct. 05, 2012shares | Dec. 31, 2011shares | |
Common Units issued in connection with public offerings | 0 | 0 | 13,800,000 | ||||||||
Units issued for cash | $ | $ 1,428 | $ 1,382 | $ 1,611 | ||||||||
Class H Unitholder’s interest in net income | $ | $ 258 | $ 217 | $ 48 | ||||||||
Partners' Capital Account, Units | 355,500,000 | 505,600,000 | 355,500,000 | 333,800,000 | 301,500,000 | ||||||
Class F Unit Distribution Rate | 35.00% | ||||||||||
Distribution Reinvestment Plan, Purchase Discount | 0.01 | 0.05 | |||||||||
Common Units issued in connection with the Distribution Reinvestment Plan | 7,700,000 | 2,800,000 | 2,300,000 | ||||||||
Class E Units entitled to aggregate cash distributions | 11.10% | ||||||||||
Class E unit maximum distribution | $ / shares | $ 1.41 | ||||||||||
Maximum Class F Distribution per Unit | $ / shares | $ 3.75 | ||||||||||
Common Units issued in connection with the equity distribution program | 21,100,000 | 21,400,000 | 16,900,000 | ||||||||
Equity Distribution Agreements, Value of Units Available to be Issued | $ | $ 328 | ||||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $ | 1,070 | ||||||||||
Partners' Capital Account, Sale of Units | $ | $ 1,428 | $ 1,382 | $ 1,611 | ||||||||
ETP [Member] | |||||||||||
Common Units issued in connection with public offerings | 13,800,000 | ||||||||||
Units issued for cash | $ | $ 657 | ||||||||||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 12,800,000 | ||||||||||
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan | 11,500,000 | ||||||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ | $ 360 | 155 | $ 109 | ||||||||
Sunoco Logistics [Member] | |||||||||||
Gain from subsidiary issuances of common units | $ | 300 | ||||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | $ | $ 2,250 | $ 1,250 | |||||||||
Common Units issued in connection with the equity distribution program | 26,800,000 | ||||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $ | $ 890 | ||||||||||
Fees and Commissions | $ | 10 | ||||||||||
Stock Issued During Period, Shares, New Issues | 2,000,000 | ||||||||||
Partners' Capital Account, Units, Sale of Units | 13,500,000 | 7,700,000 | |||||||||
Proceeds from Issuance of Common Stock | $ | $ 82 | $ 547 | $ 362 | ||||||||
Sunoco LP [Member] | |||||||||||
Partners' Capital Account, Units, Sale of Units | 9,100,000 | ||||||||||
Partners' Capital Account, Sale of Units | $ | $ 405 | ||||||||||
ETP Holdco Transaction (see Note 3) | |||||||||||
Business Combination, Consideration Transferred | $ | $ 1,400 | ||||||||||
Bakken Pipeline Transaction [Member] | |||||||||||
Class I Distributions | $ | $ 30 | $ 55 | |||||||||
Partners' Capital Account, Units, Redeemed | 30,800,000 | ||||||||||
Business Combination, Consideration Transferred | $ | $ 879 | ||||||||||
Bakken Pipeline Transaction [Member] | Parent Company [Member] | |||||||||||
Percent of total equity ownership of a subsidiary | 45.00% | ||||||||||
Class I Units | |||||||||||
Limited Partners' Capital Account, Units Outstanding | 0 | 100 | 0 | ||||||||
Limited Partners' Capital Account, Units Authorized | 0 | 100 | 0 | ||||||||
Class I Units | Bakken Pipeline Transaction [Member] | |||||||||||
Partners' Capital Account, Units | 100 | ||||||||||
Class F Units [Member] | Sunoco [Member] | |||||||||||
Partners' Capital Account, Units | 40,000,000 | ||||||||||
Class E Units | |||||||||||
Limited Partners' Capital Account, Units Outstanding | 8,853,832 | 8,853,832 | 8,853,832 | ||||||||
Limited Partners' Capital Account, Units Authorized | 8,853,832 | 8,853,832 | 8,853,832 | ||||||||
Class G Units | |||||||||||
Limited Partners' Capital Account, Units Outstanding | 90,706,000 | 90,706,000 | 90,706,000 | ||||||||
Limited Partners' Capital Account, Units Authorized | 90,706,000 | 90,706,000 | 90,706,000 | ||||||||
Class G Units | ETP Holdco Transaction (see Note 3) | |||||||||||
Partners' Capital Account, Units | 90,700,000 | ||||||||||
Class H Units | |||||||||||
Partners' Capital Account, Units | 50,200,000 | ||||||||||
Limited Partners' Capital Account, Units Outstanding | 50,160,000 | 81,001,069 | 50,160,000 | ||||||||
Limited Partners' Capital Account, Units Authorized | 50,160,000 | 81,001,069 | 50,160,000 | ||||||||
Allocation of Profits, Losses and Other by Sunoco, Percent | 50.05% | ||||||||||
Class H Units | Bakken Pipeline Transaction [Member] | |||||||||||
Allocation of Profits, Losses and Other by Sunoco, Percent | 90.05% | ||||||||||
Partners' Capital Account, Units, Redeemed | 30,800,000 | ||||||||||
Equity Distribution Agreement [Member] | |||||||||||
Fees and Commissions | $ | $ 11 | ||||||||||
Class E Units | ETP [Member] | |||||||||||
Limited Partners' Capital Account, Units Outstanding | 8,900,000 | ||||||||||
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | Sunoco Logistics [Member] | |||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ | $ 2,500 |
Equity (Change in Common Units)
Equity (Change in Common Units) (Details) - shares shares in Millions | 1 Months Ended | 12 Months Ended | |||
Aug. 31, 2014 | Feb. 28, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Number of Common Units, beginning of period | 355.5 | 333.8 | |||
Common Units issued in connection with public offerings | 0 | 0 | 13.8 | ||
Partners' Capital Account, Units, Acquisitions | 172.2 | 15.8 | 49.5 | ||
Common Units Redeemed for Class H Units | 0 | 0 | (50.2) | ||
Common Units issued in connection with the Distribution Reinvestment Plan | 7.7 | 2.8 | 2.3 | ||
Common Units issued in connection with the equity distribution program | 21.1 | 21.4 | 16.9 | ||
Stock Repurchased During Period, Shares | 0 | 0 | (0.4) | ||
Issuance of Common Units under equity incentive plans | 0.9 | 0.4 | 0.4 | ||
Number of Common Units, end of period | 505.6 | 355.5 | 333.8 | ||
Susser Merger [Member] | |||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 15.8 | ||||
Lake Charles LNG Transaction [Member] | |||||
Partners' Capital Account, Units, Redeemed | (18.7) | (51.8) | (18.7) | 0 |
Equity (Public Offerings of Com
Equity (Public Offerings of Common Units) (Details) - USD ($) shares in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | ||
Apr. 30, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Number of Common Units | 0 | 0 | 13.8 | |
Net Proceeds | $ 1,428 | $ 1,382 | $ 1,611 | |
ETP [Member] | ||||
Number of Common Units | 13.8 | |||
Net Proceeds | $ 657 |
Equity (Quarterly Distributions
Equity (Quarterly Distributions of Available Cash) (Details) - $ / shares | 3 Months Ended | ||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | |
ETP [Member] | |||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||
Distribution Made to Limited Partner, Date of Record | Feb. 8, 2016 | Nov. 5, 2015 | Aug. 6, 2015 | May 8, 2015 | Feb. 6, 2015 | Nov. 3, 2014 | Aug. 4, 2014 | May 5, 2014 | Feb. 7, 2014 | Nov. 4, 2013 | Aug. 5, 2013 | May 6, 2013 | Feb. 7, 2013 |
Distribution Made to Limited Partner, Distribution Date | Feb. 16, 2016 | Nov. 16, 2015 | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 15, 2014 | Feb. 14, 2014 | Nov. 14, 2013 | Aug. 14, 2013 | May 15, 2013 | Feb. 14, 2013 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 1.0550 | $ 1.0550 | $ 1.0350 | $ 1.0150 | $ 0.9950 | $ 0.9750 | $ 0.9550 | $ 0.9350 | $ 0.9200 | $ 0.9050 | $ 0.8938 | $ 0.8938 | $ 0.8938 |
Sunoco Logistics [Member] | |||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||
Distribution Made to Limited Partner, Date of Record | Feb. 8, 2016 | Nov. 9, 2015 | Aug. 10, 2015 | May 11, 2015 | Feb. 9, 2015 | Nov. 7, 2014 | Aug. 8, 2014 | May 9, 2014 | Feb. 10, 2014 | Nov. 8, 2013 | Aug. 8, 2013 | May 9, 2013 | Feb. 8, 2013 |
Distribution Made to Limited Partner, Distribution Date | Feb. 12, 2016 | Nov. 13, 2015 | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 15, 2014 | Feb. 14, 2014 | Nov. 14, 2013 | Aug. 14, 2013 | May 15, 2013 | Feb. 14, 2013 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.4790 | $ 0.4580 | $ 0.4380 | $ 0.4190 | $ 0.4000 | $ 0.3825 | $ 0.3650 | $ 0.3475 | $ 0.3312 | $ 0.3150 | $ 0.3000 | $ 0.2863 | $ 0.2725 |
Equity (Incentive Distribution
Equity (Incentive Distribution Relinquishments) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Currently Effective IDRs [Member] | Future IDR Relinquishments [Member] | ||||
Subsequent Event [Line Items] | ||||
Relinquishment of Incentive Distributions | $ 95 | $ 105 | $ 128 | $ 137 |
Equity (SXL Quarterly Distribut
Equity (SXL Quarterly Distributions) (Details) - Sunoco Logistics [Member] - $ / shares | 3 Months Ended | ||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | |
Distribution Made to Limited Partner [Line Items] | |||||||||||||
Distribution Made to Limited Partner, Date of Record | Feb. 8, 2016 | Nov. 9, 2015 | Aug. 10, 2015 | May 11, 2015 | Feb. 9, 2015 | Nov. 7, 2014 | Aug. 8, 2014 | May 9, 2014 | Feb. 10, 2014 | Nov. 8, 2013 | Aug. 8, 2013 | May 9, 2013 | Feb. 8, 2013 |
Distribution Made to Limited Partner, Distribution Date | Feb. 12, 2016 | Nov. 13, 2015 | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 15, 2014 | Feb. 14, 2014 | Nov. 14, 2013 | Aug. 14, 2013 | May 15, 2013 | Feb. 14, 2013 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.4790 | $ 0.4580 | $ 0.4380 | $ 0.4190 | $ 0.4000 | $ 0.3825 | $ 0.3650 | $ 0.3475 | $ 0.3312 | $ 0.3150 | $ 0.3000 | $ 0.2863 | $ 0.2725 |
Equity (Accumulated other compr
Equity (Accumulated other comprehensive income, net of tax) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Equity [Abstract] | ||
Available-for-sale securities | $ 0 | $ 3 |
Foreign currency translation adjustment | (4) | (3) |
Net loss on commodity related hedges | 0 | (1) |
Actuarial gain (loss) related to pensions and other postretirement benefits | 8 | (57) |
Equity investments, net | 0 | 2 |
Total AOCI, net of tax | $ 4 | $ (56) |
Equity (Tax amounts attributabl
Equity (Tax amounts attributable to Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Equity [Abstract] | ||
Other Comprehensive Income (Loss), Available-for-sale Securities, Tax | $ (2) | $ (1) |
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax | 4 | 2 |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax | 7 | (37) |
Other Comprehensive Income (Loss), Tax | $ 9 | $ (36) |
Unit-Based Compensation Plans79
Unit-Based Compensation Plans (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Weighted average grant-date fair value per unit award granted | $ 35.21 | $ 60.85 | $ 50.54 |
Total fair value of awards vested | $ 49 | $ 26 | $ 29 |
Unvested unit awards outstanding | 4.8 | 3.5 | |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 5.3 | ||
Employee [Member] | |||
Share based compensation, vesting term | 5 years | ||
Director [Member] | |||
Share based compensation, vesting term | 5 years | ||
ETP Unit-Based Compensation Plans [Member] | |||
Awards remaining unvested compensation expense | $ 147 | ||
Awards remaining unvested weighted average period, in years | 2 years 1 month 1 day | ||
ETP Cash Restricted Units [Member] | |||
Unvested unit awards outstanding | 0.6 | ||
Awards remaining unvested compensation expense | $ 7 | ||
Awards remaining unvested weighted average period, in years | 1 year 4 months 1 day | ||
Sunoco Logistics Unit-Based Compensation Plans [Member] | |||
Unvested unit awards outstanding | 2.5 | ||
Awards remaining unvested compensation expense | $ 52 | ||
Awards remaining unvested weighted average period, in years | 3 years |
Unit-Based Compensation Plans80
Unit-Based Compensation Plans (Activity of the awards granted to employees and non-employee directors) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Unvested awards as of December 31, 2010 , Number of Units | 3.5 | ||
Awards granted, Number of Units | 2.1 | ||
Awards vested, Number of Units | (1.2) | ||
Unvested awards as of December 31, 2011, Number of Units | 4.8 | 3.5 | |
Unvested awards as of December 31, 2010, Weighted Average Grant-Date Fair Value Per Unit | $ 53.83 | ||
Weighted average grant-date fair value per unit award granted | 35.21 | $ 60.85 | $ 50.54 |
Awards vested, Weighted Average Grant-Date Fair Value Per Unit | 48.67 | ||
Awards forfeited, Weighted Average Grant-Date Fair Value Per Unit | 55.44 | ||
Unvested awards as of December 31, 2011, Weighted Average Grant-Date Fair Value Per Unit | $ 47.61 | $ 53.83 | |
ETP Unit-Based Compensation Plans [Member] | |||
Stock Granted, Value, Share-based Compensation, Forfeited | $ (0.4) | ||
Regency Awards Converted in Merger [Member] | |||
Awards granted, Number of Units | 0.8 | ||
Weighted average grant-date fair value per unit award granted | $ 58.88 |
Income Taxes Narrative (Details
Income Taxes Narrative (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Contingency [Line Items] | |||
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration | $ 6,000,000 | ||
Deferred Tax Liabilities, Gross | 4,355,000,000 | $ 4,574,000,000 | |
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax | 550,000,000 | ||
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit | $ 4,000,000 | ||
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Other Information | 3 | ||
Unrecognized Tax Benefits, Interest on Income Taxes Expense | $ 1,000,000 | ||
Income Tax Examination, Penalties and Interest Accrued | 5,000,000 | ||
Net operating losses and alternative minimum tax credit | 155,000,000 | 116,000,000 | |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 588,000,000 | ||
Deferred Tax Assets, Valuation Allowance | 121,000,000 | 84,000,000 | |
Pending Tax Refund | 519,000,000 | ||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts | 519,000,000 | ||
State | (51,000,000) | 86,000,000 | $ (2,000,000) |
Settlements | 7,000,000 | ||
Amount Reclassed From ASU 2015-17 [Member] | |||
Income Tax Contingency [Line Items] | |||
Deferred Tax Liabilities, Gross | $ 85,000,000 | ||
Expiring 2013 to 2032 [Member] | |||
Income Tax Contingency [Line Items] | |||
Operating Loss Carryforwards | 122,000,000 | ||
Pennsylvania Constitution [Member] | |||
Income Tax Contingency [Line Items] | |||
State | 46,000,000 | ||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies | 9,000,000 | ||
Corporate Subsidiaries [Member] | |||
Income Tax Contingency [Line Items] | |||
Net operating losses and alternative minimum tax credit | 27,000,000 | ||
Net of federal tax [Member] | Pennsylvania Constitution [Member] | |||
Income Tax Contingency [Line Items] | |||
State | 30,000,000 | ||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies | $ 6,000,000 |
Income Taxes Compoenents of Fed
Income Taxes Compoenents of Federal and State Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Current expense (benefit): | |||||
Federal | $ (274) | $ 321 | $ 51 | ||
State | (51) | 86 | (2) | ||
Current expense (benefit) - Total | (325) | 407 | 49 | ||
Deferred expense (benefit): | |||||
Federal | 231 | (50) | (6) | ||
State | (29) | 1 | 54 | ||
Deferred expense (benefit) - Total | 202 | (49) | 48 | ||
Income tax expense (benefit) from continuing operations | $ (123) | [1] | $ 358 | [1] | $ 97 |
[1] | (2) Includes ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries. |
Income Taxes Statutory Income T
Income Taxes Statutory Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||
Schedule of Effective Income Tax Rate Reconciliation [Line Items] | ||||||
Income tax expense (benefit) at U.S. statutory rate of 35 percent | [1] | $ (25) | $ 217 | |||
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount | [1] | 0 | 0 | |||
Nondeductible goodwill included in the Lake Charles LNG Transaction | [1] | 0 | 105 | |||
State income taxes (net of federal income tax effects) | [1] | (37) | 54 | |||
Effective Income Tax Rate Reconciliation, Deduction, Dividends, Amount | [1] | (24) | 0 | |||
Premium on debt retirement | [1] | 0 | (10) | |||
Effective Income Tax Rate Reconciliation, Tax Settlement, Amount | [1] | (7) | 0 | |||
Foreign | [1] | 0 | (8) | |||
Effective Income Tax Rate Reconciliation, Other Reconciling Items, Amount | [1] | (30) | 0 | |||
Income tax expense (benefit) from continuing operations | (123) | [1] | 358 | [1] | $ 97 | |
Corporate Subsidiaries [Member] | ||||||
Schedule of Effective Income Tax Rate Reconciliation [Line Items] | ||||||
Income tax expense (benefit) at U.S. statutory rate of 35 percent | [2] | (25) | 217 | (166) | ||
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount | [2] | 0 | 0 | 241 | ||
Nondeductible goodwill included in the Lake Charles LNG Transaction | [2] | 0 | 105 | 0 | ||
State income taxes (net of federal income tax effects) | [2] | (56) | 9 | 31 | ||
Effective Income Tax Rate Reconciliation, Deduction, Dividends, Amount | [2] | (24) | 0 | 0 | ||
Premium on debt retirement | [2] | 0 | (10) | 0 | ||
Effective Income Tax Rate Reconciliation, Tax Settlement, Amount | [2] | (7) | 0 | 0 | ||
Foreign | [2] | 0 | (8) | 0 | ||
Effective Income Tax Rate Reconciliation, Other Reconciling Items, Amount | [2] | (30) | 0 | (13) | ||
Income tax expense (benefit) from continuing operations | [2] | $ (142) | $ 313 | 93 | ||
Partnership [Member] | ||||||
Schedule of Effective Income Tax Rate Reconciliation [Line Items] | ||||||
Income tax expense (benefit) at U.S. statutory rate of 35 percent | [1] | (166) | ||||
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount | [1] | 241 | ||||
Nondeductible goodwill included in the Lake Charles LNG Transaction | [1] | 0 | ||||
State income taxes (net of federal income tax effects) | [1] | 36 | ||||
Effective Income Tax Rate Reconciliation, Deduction, Dividends, Amount | [1] | 0 | ||||
Premium on debt retirement | [1] | 0 | ||||
Effective Income Tax Rate Reconciliation, Tax Settlement, Amount | [1] | 0 | ||||
Foreign | [1] | 0 | ||||
Effective Income Tax Rate Reconciliation, Other Reconciling Items, Amount | [1] | (14) | ||||
Income tax expense (benefit) from continuing operations | [1] | $ 97 | ||||
[1] | (2) Includes ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries. | |||||
[2] | (1) Includes ETP Holdco, Susser Holdings Corporation, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd., Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. Susser Holding Corporation, Susser Petroleum Property Company LLC and Aloha Petroleum Ltd. were deconsolidated from these financial statements in July 2015 due to the contribution of Susser Holding Corporation to Sunoco LP and the acquisition by ETE of 100% of the membership interest of Sunoco GP, the general partner of Sunoco LP (See Note 3). |
Income Taxes Tax Effects of Tem
Income Taxes Tax Effects of Temporary Differences (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Deferred income tax assets: | |||
Net operating losses and alternative minimum tax credit | $ 155 | $ 116 | |
Pension and other postretirement benefits | 36 | 47 | |
Long term debt | 61 | 53 | |
Other | 142 | 111 | |
Total deferred income tax assets | 394 | 327 | |
Valuation allowance | (121) | (84) | |
Net deferred income tax assets | 273 | 243 | |
Deferred income tax liabilities: | |||
Properties, plants and equipment | (1,305) | (1,506) | |
Inventory | 0 | (153) | |
Investment in unconsolidated affiliates | (2,889) | (2,528) | |
Trademarks | (112) | (355) | |
Other | (49) | (32) | |
Total deferred income tax liabilities | (4,355) | (4,574) | |
Accumulated deferred income taxes | (4,082) | (4,331) | $ (3,903) |
Accumulated deferred income taxes | $ (4,082) | $ (4,331) |
Income Taxes Components of Net
Income Taxes Components of Net Deferred Income Tax (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | ||
Net deferred income tax liability, beginning of year | $ (4,331) | $ (3,903) |
Susser acquisition | 0 | (488) |
Deferred Income Tax Liability as a Result of SUGS Contribution to Regency | 490 | 0 |
Tax provision (including discontinued operations) | (202) | 60 |
Net deferred income tax liability, end of year | (4,082) | (4,331) |
Increase (Decrease) in Other Deferred Liability | $ (39) | $ 0 |
Income Taxes Changes in Unrecog
Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | |||
Balance at beginning of year | $ 440 | $ 429 | $ 27 |
Additions attributable to tax positions taken in the current year | 0 | 20 | 0 |
Additions attributable to tax positions taken in prior years | 178 | (1) | 406 |
Settlements | 0 | (5) | 0 |
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations | (8) | (3) | (4) |
Balance at end of year | $ 610 | $ 440 | $ 429 |
Regulatory Matters, Commitmen87
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Narrative) (Details) | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Oct. 31, 2015USD ($) | Apr. 30, 2015USD ($) | Mar. 31, 2016USD ($) | Sep. 30, 2012USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Jan. 10, 2014USD ($) | |
Guarantor Obligations, Current Carrying Value | $ 600,000,000 | |||||||
Debt instrument interest rate | 4.50% | |||||||
Lease Expiration Date | Dec. 31, 2058 | |||||||
Rental expense under operating lease | $ 176,000,000 | $ 159,000,000 | $ 151,000,000 | |||||
Operating Leases, Rent Expense, Sublease Rentals | (16,000,000) | (26,000,000) | (24,000,000) | |||||
Operating Leases, Rent Expense, Net | 160,000,000 | 133,000,000 | 127,000,000 | |||||
Operating Leases, Rent Expense, Contingent Rentals | $ 26,000,000 | 24,000,000 | $ 22,000,000 | |||||
Site Contingency, Number of Sites Needing Remediation | 50 | |||||||
Environmental Costs Recognized, Recovery Credited to Expense | $ 19,000,000 | |||||||
Accrual for Environmental Loss Contingencies | 367,000,000 | 401,000,000 | ||||||
Payments for Environmental Liabilities | 38,000,000 | 48,000,000 | ||||||
Payments to Acquire Businesses, Gross | $ 382,000,000 | |||||||
Proposed Environmental Penalty | 0 | |||||||
FGT | ||||||||
Proceeds from Legal Settlements | $ 100,000,000 | |||||||
Loss Contingency, Damages Awarded, Value | $ 19,000,000 | 1,000,000 | ||||||
AmeriGas [Member] | ||||||||
Business Combination, Contingent Consideration, Liability | $ 1,550,000,000 | |||||||
Southern Union [Member] | ||||||||
Percentage Of Recovery | 50.00% | |||||||
Loss Contingency, Estimated Recovery from Third Party | 150,000 | |||||||
Related To Deductibles [Member] | ||||||||
Loss Contingency Accrual, at Carrying Value | $ 40,000,000 | $ 37,000,000 | ||||||
Sea Robin Rate Case [Member] | ||||||||
Customer Refundable Fees, Refund Payments | 11,000,000 | |||||||
Texas Commission on Environmental Quality [Member] | ||||||||
Accrual for Environmental Loss Contingencies | 300,000 | |||||||
Final Judgement [Member] | ||||||||
Gain Contingency, Unrecorded Amount | 536,000,000 | |||||||
New Mexico Environmental Department [Member] | ||||||||
Accrual for Environmental Loss Contingencies | 250,000 | |||||||
Disgorgement [Member] | ||||||||
Gain Contingency, Unrecorded Amount | 595,000,000 | |||||||
Expense Reimbursement [Member] | ||||||||
Gain Contingency, Unrecorded Amount | $ 1,000,000 | |||||||
MTBE Sites [Member] | ||||||||
Site Contingency, Number of Sites Needing Remediation | 19 | |||||||
Compensatory Damages [Member] | ||||||||
Gain Contingency, Unrecorded Amount | $ 319,000,000 | |||||||
Dropdown of Sunoco LLC Interest [Member] | ||||||||
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage | 31.58% | |||||||
Payments to Acquire Businesses, Gross | $ 775,000,000 | |||||||
Equity Issued in Business Combination, Fair Value Disclosure | $ 41,000,000 | |||||||
Dropdown of Sunoco LLC Interest [Member] | Sunoco LP [Member] | ||||||||
Payments to Acquire Businesses, Gross | $ 2,030,000,000 | |||||||
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member] | ||||||||
Debt instrument interest rate | 6.375% | |||||||
Senior Notes | $ 800,000,000 |
Regulatory Matters, Commitmen88
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Future minimum lease commitments) (Details) $ in Millions | Dec. 31, 2015USD ($) |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
2,015 | $ 57 |
2,016 | 53 |
2,017 | 44 |
2,018 | 39 |
2,019 | 40 |
Thereafter | 252 |
Total Future Rent Payments | 485 |
Future Rental Income | (34) |
Net Future Rental Payments | $ 451 |
Regulatory Matters, Commitmen89
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Liabilities Related to Environmental Matters) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Environmental Remediation Obligations [Abstract] | ||
Accrued Environmental Loss Contingencies, Current | $ 41 | $ 41 |
Accrued Environmental Loss Contingencies, Noncurrent | 326 | 360 |
Accrual for Environmental Loss Contingencies | $ 367 | $ 401 |
Derivative assets and liabilt90
Derivative assets and liabilties (Outstanding commodity-related derivatives) (Details) | 12 Months Ended | ||
Dec. 31, 2015MMbtubblbushels | Dec. 31, 2014MMbtubblbushels | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | |||
Notional Volume | (71,340,000) | (46,150,000) | |
Term Of Commodity Derivatives | 2,015 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,017 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps Futures [Member] | |||
Notional Volume | (14,380,000) | (34,304,000) | |
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps Futures [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps Futures [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,018 | 2,016 | |
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Notional Volume | (6,522,500) | (57,500) | |
Term Of Commodity Derivatives | 2,015 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,017 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | |||
Notional Volume | (21,922,484) | (9,116,777) | |
Term Of Commodity Derivatives | 2,015 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,017 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas Liquids [Member] | Forward Swaps [Member] | |||
Notional Volume | (8,146,800) | (4,417,400) | |
Term Of Commodity Derivatives | 2,015 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas Liquids [Member] | Forward Swaps [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Natural Gas Liquids [Member] | Forward Swaps [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,018 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Refined Products [Member] | Future [Member] | |||
Notional Volume | (993,000) | (13,745,755) | |
Term Of Commodity Derivatives | 2,015 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Refined Products [Member] | Future [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Refined Products [Member] | Future [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,017 | ||
Mark to Market Derivatives [Member] | Non Trading [Member] | Corn [Member] | Future [Member] | |||
Notional Volume | bushels | (1,185,000) | 0 | |
Term Of Commodity Derivatives | 2,016 | ||
Mark to Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Fixed Swaps Futures [Member] | |||
Notional Volume | (602,500) | (232,500) | |
Term Of Commodity Derivatives | 2,015 | ||
Mark to Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Fixed Swaps Futures [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Mark to Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Fixed Swaps Futures [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,017 | ||
Mark to Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Notional Volume | [1] | (31,240,000) | (13,907,500) |
Mark to Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Mark to Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,017 | 2,016 | |
Mark to Market Derivatives [Member] | Trading [Member] | Natural Gas [Member] | Call Option [Member] | |||
Notional Volume | 0 | (5,000,000) | |
Term Of Commodity Derivatives | 2,015 | ||
Mark to Market Derivatives [Member] | Trading [Member] | Power [Member] | Call Option [Member] | |||
Notional Volume | (1,300,647) | (198,556) | |
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Mark to Market Derivatives [Member] | Trading [Member] | Power [Member] | Forward Swaps [Member] | |||
Notional Volume | (357,092) | (288,775) | |
Term Of Commodity Derivatives | 2,015 | ||
Mark to Market Derivatives [Member] | Trading [Member] | Power [Member] | Forward Swaps [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Mark to Market Derivatives [Member] | Trading [Member] | Power [Member] | Forward Swaps [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,017 | ||
Mark to Market Derivatives [Member] | Trading [Member] | Power [Member] | Future [Member] | |||
Notional Volume | (109,791) | (156,000) | |
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Mark to Market Derivatives [Member] | Trading [Member] | Power [Member] | Put Option [Member] | |||
Notional Volume | (260,534) | (72,000) | |
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Mark to Market Derivatives [Member] | Trading [Member] | Crude Oil [Member] | Future [Member] | |||
Notional Volume | bbl | (591,000) | 0 | |
Mark to Market Derivatives [Member] | Trading [Member] | Crude Oil [Member] | Future [Member] | Minimum [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Mark to Market Derivatives [Member] | Trading [Member] | Crude Oil [Member] | Future [Member] | Maximum [Member] | |||
Term Of Commodity Derivatives | 2,017 | ||
Fair Value Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Fixed Swaps Futures [Member] | |||
Notional Volume | (37,555,000) | (39,287,500) | |
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Fair Value Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Notional Volume | (37,555,000) | (39,287,500) | |
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Fair Value Hedging [Member] | Non Trading [Member] | Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | |||
Notional Volume | (37,555,000) | (39,287,500) | |
Term Of Commodity Derivatives | 2,016 | 2,015 | |
[1] | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Derivative assets and liabilt91
Derivative assets and liabilties (Interest rate swaps outstanding) (Details) - ETP [Member] - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
December 2018 [Member] | |||
Type | [1] | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | |
Notional amount outstanding | $ 1,200 | $ 0 | |
June 2021 [Member] | |||
Type | [1] | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | |
Notional amount outstanding | $ 300 | 0 | |
Floating Interest Rate Of 6.70 Percent [Member] | |||
Type | [1],[2] | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | |
Notional amount outstanding | [2] | $ 0 | 200 |
Forward-Starting Swaps [Member] | July 2015 [Member] | |||
Type | [1],[3] | Forward-starting to pay a fixed rate of 3.38% and receive a floating rate | |
Notional amount outstanding | [3] | $ 0 | 200 |
Forward-Starting Swaps [Member] | July 2016 [Member] | |||
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | |
Notional amount outstanding | [2] | $ 200 | 200 |
Forward-Starting Swaps [Member] | July 2017 [Member] | |||
Type | [1],[4] | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | |
Notional amount outstanding | [4] | $ 300 | 300 |
Forward-Starting Swaps [Member] | July 2018 [Member] | |||
Type | [1],[4] | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | |
Notional amount outstanding | [4] | $ 200 | 200 |
Forward-Starting Swaps [Member] | July 2019 [Member] | |||
Type | [1],[4] | Forward-starting to pay a fixed rate of 3.25% and receive a floating rate | |
Notional amount outstanding | [4] | $ 200 | $ 300 |
[1] | (1) Floating rates are based on 3-month LIBOR. | ||
[2] | (3) Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date. | ||
[3] | (2) Represents the effective date. These forward-starting swaps have terms of 10 years with a mandatory termination date the same as the effective date. | ||
[4] | (4) Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. |
Derivative assets and liabilt92
Derivative assets and liabilties (Fair Value of Derivative Instruments) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Total derivative assets | $ 448 | $ 770 |
Total derivative liabilities | (526) | (771) |
Derivative Asset, Fair Value, Net | 122 | 174 |
Derivative Liability, Fair Value, Net | 200 | 175 |
Designated as Hedging Instrument [Member] | ||
Total derivative assets | 38 | 43 |
Total derivative liabilities | (3) | 0 |
Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member] | ||
Total derivative assets | 38 | 43 |
Total derivative liabilities | (3) | 0 |
Not Designated as Hedging Instrument [Member] | ||
Total derivative assets | 410 | 727 |
Total derivative liabilities | (523) | (771) |
Not Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member] | ||
Total derivative assets | 353 | 617 |
Total derivative liabilities | (306) | (577) |
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member] | ||
Total derivative assets | 57 | 107 |
Total derivative liabilities | (41) | (23) |
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member] | ||
Total derivative assets | 3 | |
Total derivative liabilities | (171) | (155) |
Asset Fair Value, Netting Offset [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member] | ||
Total derivative assets | 0 | |
Embedded Derivatives in Preferred Units [Member] | Not Designated as Hedging Instrument [Member] | ||
Total derivative assets | 0 | 0 |
Total derivative liabilities | (5) | (16) |
Broker cleared derivative contracts [Member] | ||
Total derivative assets | 391 | 660 |
Total derivative liabilities | $ (309) | $ (577) |
Derivative assets and liabilt93
Derivative assets and liabilties (Netting table) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 448 | $ 770 |
Derivative Liability, Fair Value, Gross Liability | (526) | (771) |
Derivative Asset, Fair Value, Amount Offset Against Collateral | (17) | (19) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 17 | 19 |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (309) | (577) |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 309 | 577 |
Derivative Asset, Fair Value, Net | 122 | 174 |
Derivative Liability, Fair Value, Net | (200) | (175) |
Without offsetting agreements [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 3 |
Derivative Liability, Fair Value, Gross Liability | (176) | (171) |
OTC Contracts [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 57 | 107 |
Derivative Liability, Fair Value, Gross Liability | (41) | (23) |
Broker cleared derivative contracts [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 391 | 660 |
Derivative Liability, Fair Value, Gross Liability | (309) | (577) |
Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 410 | 727 |
Derivative Liability, Fair Value, Gross Liability | $ (523) | $ (771) |
Derivative assets and liabilt94
Derivative assets and liabilties (Partnership's derivative assets and liabilities, recognized OCI on derivatives (effective portion)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | $ 21 | $ (8) | $ 8 |
Cost of Sales [Member] | Commodity [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | $ 21 | $ (8) | $ 8 |
Derivative assets and liabilt95
Derivative assets and liabilties (Partnership's derivative assets and liabilities, amount of gain/(loss) reclassified from AOCI into income (effective portion)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | $ 0 | $ 0 | $ (1) |
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | 0 | (3) | 4 |
Amount of Gain (Loss) Recognized in Income on Ineffective Portion | 21 | (8) | 8 |
Amount of Gain (Loss) Recognized In Income On Derivatives | 6 | 39 | 15 |
Gains (losses) on interest rate derivatives | (18) | (157) | 44 |
Embedded Derivatives in Preferred Units [Member] | Other Income (Expenses) [Member] | |||
Amount of Gain (Loss) Recognized In Income On Derivatives | 12 | 3 | 6 |
Commodity [Member] | |||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | 0 | 0 | (1) |
Commodity [Member] | Cost of Sales [Member] | |||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | 0 | (3) | 4 |
Amount of Gain (Loss) Recognized in Income on Ineffective Portion | 21 | (8) | 8 |
Trading [Member] | Commodity [Member] | Cost of Sales [Member] | |||
Amount of Gain (Loss) Recognized In Income On Derivatives | (11) | (6) | (11) |
Non Trading [Member] | Commodity [Member] | Cost of Sales [Member] | |||
Amount of Gain (Loss) Recognized In Income On Derivatives | 23 | 199 | (21) |
Non Trading [Member] | Commodity [Member] | Deferred Gas Purchases [Member] | |||
Amount of Gain (Loss) Recognized In Income On Derivatives | $ 0 | $ 0 | $ (3) |
Retirement Benefits (Narratives
Retirement Benefits (Narratives) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted average grant-date fair value per unit award granted | $ 35.21 | $ 60.85 | $ 50.54 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 5.3 | ||
Unvested unit awards outstanding | 4.8 | 3.5 | |
Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Large Cap US Equitiies | 100.00% | 100.00% | |
2,015 | $ 16 | ||
Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Large Cap US Equitiies | 56.00% | ||
Fixed Income Securities | 33.00% | ||
Cash Fund Investments | 11.00% | ||
2,015 | $ 10 | ||
ETP [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Contributions to the 401(k) savings plan | 39 | $ 50 | $ 45 |
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Large Cap US Equitiies | 56.00% | ||
Fixed Income Securities | 38.00% | ||
Cash Fund Investments | 6.00% | ||
Sunoco [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent | $ 200 | ||
Cash [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum | 10.00% | ||
Equity [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum | 25.00% | ||
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum | 35.00% | ||
Fixed Income Investments [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum | 65.00% | ||
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum | 75.00% |
Retirement Benefits Obligations
Retirement Benefits Obligations and Funded Status (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | $ 0 | $ 0 | |
Change in Plan Assets, Dispositions | 0 | (5) | |
Change in Benefit Obligations, Dispositions | 0 | (1) | |
Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Interest cost | 25 | 31 | |
Benefit obligation | 718 | ||
Fair value of plan assets | 598 | ||
Amount underfunded | 120 | ||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Defined Benefit Plan, Amounts Recognized in Balance Sheet | (120) | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 18 | ||
Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Interest cost | 4 | 5 | |
Actuarial Loss and Other | (6) | 2 | |
Defined Benefit Plan, Actual Return on Plan Assets | 0 | 6 | |
Defined Benefit Plan, Contributions by Employer | 8 | 8 | |
Benefit obligation | 180 | 202 | $ 223 |
Fair value of plan assets | 253 | 265 | 284 |
Amount underfunded | (73) | (63) | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Non-current assets | 97 | 90 | |
Current liabilities | (2) | (2) | |
Non-current liabilities | (22) | (25) | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet | 73 | 63 | |
Defined Benefit Plan, Amortization of Net Gains (Losses) | (17) | (20) | |
Defined Benefit Plan, Benefits Paid | 20 | 28 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax | 15 | 17 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | (2) | (3) | |
Southern Union [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 15 | 598 | |
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 253 | 265 | |
Funded Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | (691) | ||
Change in Plan Assets, Dispositions | 0 | ||
Change in Benefit Obligations, Dispositions | 0 | ||
Funded Plans [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Interest cost | 23 | 28 | |
Actuarial Loss and Other | 16 | 130 | |
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | (27) | ||
Change in Plan Assets, Dispositions | 0 | ||
Change in Benefit Obligations, Dispositions | 0 | ||
Defined Benefit Plan, Actual Return on Plan Assets | 16 | 70 | |
Defined Benefit Plan, Contributions by Employer | 138 | 0 | |
Benefit obligation | 20 | 718 | 632 |
Fair value of plan assets | 15 | 598 | 600 |
Amount underfunded | 5 | ||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Non-current assets | 0 | 0 | |
Current liabilities | 0 | 0 | |
Non-current liabilities | (5) | (120) | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet | (5) | ||
Defined Benefit Plan, Amortization of Net Gains (Losses) | 2 | 18 | |
Defined Benefit Plan, Benefits Paid | 46 | 45 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax | 0 | 0 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 2 | ||
Unfunded Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | 0 | 0 | |
Change in Benefit Obligations, Dispositions | 0 | 0 | |
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Interest cost | 2 | 3 | |
Actuarial Loss and Other | (2) | 10 | |
Benefit obligation | 57 | 65 | 61 |
Amount underfunded | 57 | 65 | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Non-current assets | 0 | 0 | |
Current liabilities | (9) | (9) | |
Non-current liabilities | (48) | (56) | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet | (57) | (65) | |
Defined Benefit Plan, Amortization of Net Gains (Losses) | 4 | 7 | |
Defined Benefit Plan, Benefits Paid | 8 | 9 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax | 0 | 0 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 4 | 7 | |
Change in Plan Assets [Member] | Unfunded Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Change in Plan Assets, Dispositions | 0 | 0 | |
Change in Plan Assets [Member] | Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Change in Plan Assets [Member] | Unfunded Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | 0 | 0 | |
Change in Plan Assets [Member] | Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Actual Return on Plan Assets | 0 | 0 | |
Defined Benefit Plan, Contributions by Employer | 0 | 0 | |
Fair value of plan assets | 0 | $ 0 | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Defined Benefit Plan, Benefits Paid | $ 0 | $ 0 |
Retirement Benefits Components
Retirement Benefits Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 41 | $ (14) |
Interest cost | 25 | 31 |
Expected return on plan assets | (16) | (40) |
Prior service cost amortization | 0 | 0 |
Actuarial loss amortization | 0 | 1 |
Settlements | (32) | 4 |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Net Periodic Benefit Cost | (3) | (3) |
Interest cost | 4 | 5 |
Expected return on plan assets | (8) | (8) |
Prior service cost amortization | 1 | 1 |
Actuarial loss amortization | 0 | 1 |
Settlements | 0 | 0 |
Funded Plans [Member] | Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Interest cost | $ 23 | $ 28 |
Retirement Benefits Summary for
Retirement Benefits Summary for Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation | $ 180 | $ 202 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | 253 | 265 |
Funded Plans [Member] | Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation | 20 | 718 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation | 20 | 718 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | 15 | 598 |
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation | 57 | 65 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation | 57 | 65 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | $ 0 | $ 0 |
Retirement Benefits Weighted-Av
Retirement Benefits Weighted-Average Assumptions Used in Determining Benefit Obligations (Details) | Dec. 31, 2015 | Dec. 31, 2014 |
Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 3.59% | 3.62% |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 2.38% | 2.24% |
Retirement Benefits Assumed Hea
Retirement Benefits Assumed Health Care Cost Trend Rates (Details) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 7.16% | 7.09% |
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.39% | 5.41% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2,018 | 2,018 |
Retirement Benefits Schedule Of
Retirement Benefits Schedule Of Weighted-Average Assumptions To Determine Defined Benefit Plans And Postretirement Benefit Plans Expense (Details) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.65% | 4.65% |
Expected long term return on assets, tax exempt accounts | 7.50% | 7.50% |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 2.79% | 3.02% |
Expected long term return on assets, tax exempt accounts | 7.00% | 7.00% |
Expected long term return on assets, taxable accounts | 4.50% | 4.50% |
Retirement Benefits Fair Value
Retirement Benefits Fair Value of Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | $ 253 | $ 265 | $ 284 | |
Large Cap US Equitiies | 56.00% | |||
Fixed Income Securities | 33.00% | |||
Cash Fund Investments | 11.00% | |||
Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | $ 598 | |||
Large Cap US Equitiies | 100.00% | 100.00% | ||
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | $ 18 | |||
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 133 | |||
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 15 | |||
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 102 | |||
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 253 | $ 265 | ||
Large Cap US Equitiies | 56.00% | |||
Fixed Income Securities | 38.00% | |||
Cash Fund Investments | 6.00% | |||
Southern Union [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 15 | $ 598 | ||
Southern Union [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 18 | 9 | ||
Southern Union [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 25 | |||
Southern Union [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | [1] | 133 | 131 | |
Southern Union [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | [2] | 15 | 110 | |
Southern Union [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 102 | 125 | ||
Southern Union [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 463 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 151 | 140 | ||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | 25 | ||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 9 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 25 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 131 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 102 | 125 | ||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 15 | 573 | ||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 110 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 125 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 463 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | $ 0 | 0 | ||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | $ 0 | |||
[1] | (1) Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015. | |||
[2] | (1) Comprised of approximately 100% equities as of December 31, 2015. |
Retirement Benefits Expected Fu
Retirement Benefits Expected Future Benefit Payments (Details) $ in Millions | Dec. 31, 2015USD ($) |
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | $ 21 |
2,016 | 20 |
2,017 | 19 |
2,018 | 17 |
2,019 | 16 |
2020 - 2024 | 58 |
Other Postretirement Benefit Plans, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | 10 |
Pension Plans, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | 16 |
Funded Plans [Member] | Pension Plans, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | 20 |
2,016 | 0 |
2,017 | 0 |
2,018 | 0 |
2,019 | 0 |
2020 - 2024 | 0 |
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | 9 |
2,016 | 7 |
2,017 | 7 |
2,018 | 6 |
2,019 | 6 |
2020 - 2024 | $ 2 |
Related Party Transactions (Nar
Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction, Amounts of Transaction | $ 75 | |
January 2016 Agreement [Member] | ||
Management Fees Revenue | $ 95 |
Related Party Transactions Rela
Related Party Transactions Related Party - Affiliated Revenues (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction [Line Items] | |||
Affiliated revenues | $ 417 | $ 965 | $ 1,442 |
Related Party Transactions R107
Related Party Transactions Related Party - Affiliate AR and Affiliate AP (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | $ 268 | $ 139 |
Accounts Payable, Related Parties, Current | 25 | 25 |
ETE | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 110 | 11 |
PES | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 10 | 6 |
FGT | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 13 | 9 |
Accounts Payable, Related Parties, Current | 1 | 2 |
Lake Charles LNG | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 36 | 3 |
Accounts Payable, Related Parties, Current | 3 | 2 |
Trans-Pecos Pipeline, LLC [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 29 | 0 |
Comanche Trail Pipeline, LLC [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 22 | 0 |
Other | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 45 | 110 |
Accounts Payable, Related Parties, Current | 16 | 21 |
Sunoco LP [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 3 | 0 |
Accounts Payable, Related Parties, Current | $ 5 | $ 0 |
Reportable Segments (Segment Ad
Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Adjusted EBITDA | $ 5,714 | $ 5,710 | $ 4,404 |
Depreciation, depletion and amortization | (1,929) | (1,669) | (1,296) |
Interest expense, net | (1,291) | (1,165) | (1,013) |
Gain on sale of AmeriGas common units | 0 | 177 | 87 |
Impairment losses | 339 | 370 | 689 |
Impairment losses | (205) | (370) | |
Gains (losses) on interest rate derivatives | (18) | (157) | 44 |
Non-cash unit-based compensation expense | (79) | (68) | (54) |
Unrealized gains (losses) on commodity risk management activities | (65) | 112 | 42 |
Inventory valuation adjustments | (104) | (473) | 3 |
Losses on extinguishments of debt | (43) | (25) | (7) |
Non-operating environmental remediation | 0 | 0 | 168 |
Adjusted EBITDA related to discontinued operations | 0 | (27) | (76) |
Adjusted EBITDA related to unconsolidated affiliates | (937) | (748) | (722) |
Equity in earnings of unconsolidated affiliates | 469 | 332 | 236 |
Other, net | 20 | (36) | 19 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 1,398 | 1,593 | 810 |
Intrastate Transportation And Storage [Member] | |||
Segment Adjusted EBITDA | 543 | 559 | 521 |
Depreciation, depletion and amortization | (129) | (125) | (122) |
Impairment losses | 0 | 0 | |
Equity in earnings of unconsolidated affiliates | 32 | 27 | 30 |
Interstate Transportation and Storage [Member] | |||
Segment Adjusted EBITDA | 1,155 | 1,212 | 1,368 |
Depreciation, depletion and amortization | (210) | (203) | (244) |
Impairment losses | 99 | 0 | |
Equity in earnings of unconsolidated affiliates | 197 | 196 | 182 |
Midstream [Member] | |||
Segment Adjusted EBITDA | 1,250 | 1,318 | 757 |
Depreciation, depletion and amortization | (720) | (569) | (335) |
Impairment losses | 0 | 370 | |
Equity in earnings of unconsolidated affiliates | (19) | 10 | 1 |
Liquids Transportation And Services [Member] | |||
Segment Adjusted EBITDA | 731 | 591 | 350 |
Depreciation, depletion and amortization | (126) | (113) | (91) |
Impairment losses | 106 | 0 | |
Equity in earnings of unconsolidated affiliates | (2) | (3) | (2) |
Investment in Sunoco Logistics [Member] | |||
Segment Adjusted EBITDA | 1,153 | 971 | 871 |
Depreciation, depletion and amortization | (382) | (296) | (265) |
Impairment losses | 0 | 0 | |
Equity in earnings of unconsolidated affiliates | 21 | 23 | 18 |
Retail Marketing [Member] | |||
Segment Adjusted EBITDA | 583 | 731 | 325 |
Depreciation, depletion and amortization | $ (190) | (189) | (114) |
Impairment losses | 0 | ||
Equity in earnings of unconsolidated affiliates | $ 194 | 2 | 2 |
Other Segments [Member] | |||
Segment Adjusted EBITDA | 299 | 328 | 212 |
Depreciation, depletion and amortization | (172) | (174) | (125) |
Impairment losses | 0 | 0 | |
Equity in earnings of unconsolidated affiliates | $ 46 | $ 77 | $ 5 |
Reportable Segments (Financial
Reportable Segments (Financial Information by Segment) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Advances to and investments in unconsolidated affiliates | $ 5,003 | $ 3,760 | $ 5,003 | $ 3,760 | $ 4,050 | ||||||
Property, Plant and Equipment, Additions | 8,167 | 5,494 | 3,327 | ||||||||
Total assets | 65,173 | 62,518 | 65,173 | 62,518 | 49,900 | ||||||
Equity in earnings from unconsolidated affiliates | 469 | 332 | 236 | ||||||||
Depreciation, depletion and amortization | 1,929 | 1,669 | 1,296 | ||||||||
Cost of products sold | 27,029 | 48,414 | 42,580 | ||||||||
Revenues | 5,825 | $ 6,601 | $ 11,540 | $ 10,326 | 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | 34,292 | 55,475 | 48,335 |
Intrastate Transportation And Storage [Member] | |||||||||||
Advances to and investments in unconsolidated affiliates | 406 | 423 | 406 | 423 | 443 | ||||||
Property, Plant and Equipment, Additions | 105 | 169 | 47 | ||||||||
Total assets | 4,882 | 4,983 | 4,882 | 4,983 | 5,048 | ||||||
Equity in earnings from unconsolidated affiliates | 32 | 27 | 30 | ||||||||
Depreciation, depletion and amortization | 129 | 125 | 122 | ||||||||
Cost of products sold | 1,554 | 2,169 | 1,737 | ||||||||
Revenues | 2,250 | 2,857 | 2,452 | ||||||||
Intrastate Transportation And Storage [Member] | External Customers [Member] | |||||||||||
Revenues | 1,912 | 2,645 | 2,242 | ||||||||
Intrastate Transportation And Storage [Member] | Intersegment [Member] | |||||||||||
Revenues | 338 | 212 | 210 | ||||||||
Interstate Transportation and Storage [Member] | |||||||||||
Advances to and investments in unconsolidated affiliates | 2,516 | 2,649 | 2,516 | 2,649 | 2,588 | ||||||
Property, Plant and Equipment, Additions | 860 | 411 | 152 | ||||||||
Total assets | 11,345 | 10,779 | 11,345 | 10,779 | 11,537 | ||||||
Equity in earnings from unconsolidated affiliates | 197 | 196 | 182 | ||||||||
Depreciation, depletion and amortization | 210 | 203 | 244 | ||||||||
Revenues | 1,025 | 1,072 | 1,309 | ||||||||
Interstate Transportation and Storage [Member] | External Customers [Member] | |||||||||||
Revenues | 1,008 | 1,057 | 1,270 | ||||||||
Interstate Transportation and Storage [Member] | Intersegment [Member] | |||||||||||
Revenues | 17 | 15 | 39 | ||||||||
Midstream [Member] | |||||||||||
Advances to and investments in unconsolidated affiliates | 117 | 138 | 117 | 138 | 36 | ||||||
Property, Plant and Equipment, Additions | 2,172 | 1,298 | 1,114 | ||||||||
Total assets | 17,111 | 15,562 | 17,111 | 15,562 | 7,847 | ||||||
Equity in earnings from unconsolidated affiliates | (19) | 10 | 1 | ||||||||
Depreciation, depletion and amortization | 720 | 569 | 335 | ||||||||
Cost of products sold | 3,266 | 4,893 | 3,130 | ||||||||
Revenues | 5,071 | 6,823 | 4,276 | ||||||||
Midstream [Member] | External Customers [Member] | |||||||||||
Revenues | 2,622 | 4,770 | 3,220 | ||||||||
Midstream [Member] | Intersegment [Member] | |||||||||||
Revenues | 2,449 | 2,053 | 1,056 | ||||||||
Liquids Transportation And Services [Member] | |||||||||||
Advances to and investments in unconsolidated affiliates | 32 | 31 | 32 | 31 | 29 | ||||||
Property, Plant and Equipment, Additions | 2,109 | 427 | 448 | ||||||||
Total assets | 7,235 | 4,568 | 7,235 | 4,568 | 4,321 | ||||||
Equity in earnings from unconsolidated affiliates | (2) | (3) | (2) | ||||||||
Depreciation, depletion and amortization | 126 | 113 | 91 | ||||||||
Cost of products sold | 2,595 | 3,166 | 1,654 | ||||||||
Revenues | 3,481 | 3,911 | 2,126 | ||||||||
Liquids Transportation And Services [Member] | External Customers [Member] | |||||||||||
Revenues | 3,232 | 3,730 | 2,025 | ||||||||
Liquids Transportation And Services [Member] | Intersegment [Member] | |||||||||||
Revenues | 249 | 181 | 101 | ||||||||
Investment in Sunoco Logistics [Member] | |||||||||||
Advances to and investments in unconsolidated affiliates | 247 | 226 | 247 | 226 | 125 | ||||||
Property, Plant and Equipment, Additions | 2,126 | 2,510 | 1,018 | ||||||||
Total assets | 15,423 | 13,619 | 15,423 | 13,619 | 11,650 | ||||||
Equity in earnings from unconsolidated affiliates | 21 | 23 | 18 | ||||||||
Depreciation, depletion and amortization | 382 | 296 | 265 | ||||||||
Cost of products sold | 9,307 | 17,135 | 15,600 | ||||||||
Revenues | 10,486 | 18,088 | 16,639 | ||||||||
Investment in Sunoco Logistics [Member] | External Customers [Member] | |||||||||||
Revenues | 10,302 | 17,920 | 16,480 | ||||||||
Investment in Sunoco Logistics [Member] | Intersegment [Member] | |||||||||||
Revenues | 184 | 168 | 159 | ||||||||
Retail Marketing [Member] | |||||||||||
Advances to and investments in unconsolidated affiliates | 1,541 | 19 | 1,541 | 19 | 22 | ||||||
Property, Plant and Equipment, Additions | 412 | 259 | 176 | ||||||||
Total assets | 3,218 | 8,917 | 3,218 | 8,917 | 3,936 | ||||||
Equity in earnings from unconsolidated affiliates | 194 | 2 | 2 | ||||||||
Depreciation, depletion and amortization | 190 | 189 | 114 | ||||||||
Cost of products sold | 11,174 | 21,154 | 20,150 | ||||||||
Revenues | 12,482 | 22,487 | 21,012 | ||||||||
Retail Marketing [Member] | External Customers [Member] | |||||||||||
Revenues | 12,478 | 22,484 | 21,004 | ||||||||
Retail Marketing [Member] | Intersegment [Member] | |||||||||||
Revenues | 4 | 3 | 8 | ||||||||
Other Segments [Member] | |||||||||||
Advances to and investments in unconsolidated affiliates | 144 | 274 | 144 | 274 | 807 | ||||||
Property, Plant and Equipment, Additions | 383 | 420 | 372 | ||||||||
Total assets | $ 5,959 | $ 4,090 | 5,959 | 4,090 | 5,561 | ||||||
Equity in earnings from unconsolidated affiliates | 46 | 77 | 5 | ||||||||
Depreciation, depletion and amortization | 172 | 174 | 125 | ||||||||
Cost of products sold | 2,855 | 2,975 | 2,337 | ||||||||
Revenues | 3,292 | 3,331 | 2,597 | ||||||||
Other Segments [Member] | External Customers [Member] | |||||||||||
Revenues | 2,738 | 2,869 | 2,094 | ||||||||
Other Segments [Member] | Intersegment [Member] | |||||||||||
Revenues | 554 | 462 | 503 | ||||||||
Intersegment Eliminations [Member] | |||||||||||
Cost of products sold | (3,722) | (3,078) | (2,028) | ||||||||
Revenues | $ (3,795) | $ (3,094) | $ (2,076) |
Quarterly Financial Data Qarter
Quarterly Financial Data Qarterly Financial Data Table(Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Data [Abstract] | |||||||||||
Revenues | $ 5,825 | $ 6,601 | $ 11,540 | $ 10,326 | $ 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | $ 34,292 | $ 55,475 | $ 48,335 |
Operating income | 187 | 576 | 888 | 608 | 159 | 809 | 769 | 706 | 2,259 | 2,443 | 1,619 |
Net income | 21 | 393 | 839 | 268 | (245) | 513 | 548 | 483 | 1,521 | 1,299 | 746 |
Common Unitholders’ interest in net income (loss) | $ (327) | $ 59 | $ 298 | $ (48) | $ (90) | $ 148 | $ 295 | $ 253 | $ (18) | $ 606 | $ (98) |
Basic net income (loss) per Common Unit | $ (0.68) | $ 0.11 | $ 0.67 | $ (0.17) | $ (0.28) | $ 0.44 | $ 0.92 | $ 0.76 | $ (0.09) | $ 1.77 | $ (0.18) |
Diluted net income (loss) per Common Unit | $ (0.68) | $ 0.10 | $ 0.67 | $ (0.17) | $ (0.28) | $ 0.44 | $ 0.92 | $ 0.76 | $ (0.10) | $ 1.77 | $ (0.18) |
Quarterly Financial Data Quarte
Quarterly Financial Data Quarterly Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Inventory Valuation Reserves | $ 456 | $ 120 | $ 456 | ||
Impairment losses | 339 | 370 | $ 689 | ||
Impairment losses | $ 205 | $ 370 | |||
Excess of distribution made above net income | $ 934 | $ 544 |