Document And Entity Information
Document And Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Oct. 30, 2015 | |
Entity Information [Abstract] | ||
Entity Registrant Name | Energy Transfer Partners, L.P. | |
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 | 501,945,249 | |
Document Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 858 | $ 663 |
Accounts receivable, net | 2,413 | 3,360 |
Accounts receivable from related companies | 428 | 139 |
Inventories | 1,223 | 1,460 |
Exchanges receivable | 38 | 44 |
Derivative assets | 10 | 81 |
Other current assets | 355 | 296 |
Total current assets | 5,325 | 6,043 |
Property, plant and equipment | 48,286 | 43,404 |
Accumulated depreciation and depletion | (5,465) | (4,497) |
Property, plant and equipment, net | 42,821 | 38,907 |
Advances to and investments in unconsolidated affiliates | 5,119 | 3,760 |
Non-current derivative assets | 15 | 10 |
Other non-current assets, net | 738 | 786 |
Intangible assets, net | 4,494 | 5,526 |
Goodwill | 5,633 | 7,642 |
Total assets | 64,145 | 62,674 |
Current liabilities: | ||
Accounts payable | 2,037 | 3,348 |
Accounts payable to related companies | 256 | 25 |
Exchanges payable | 87 | 183 |
Derivative liabilities | 2 | 21 |
Accrued and other current liabilities | 2,100 | 2,099 |
Current maturities of long-term debt | 1 | 1,008 |
Total current liabilities | 4,483 | 6,684 |
Long-term debt, less current maturities | 27,449 | 24,973 |
Non-current derivative liabilities | 189 | 154 |
Deferred income taxes | 3,768 | 4,246 |
Other non-current liabilities | $ 1,144 | $ 1,258 |
Commitments and contingencies | ||
Series A Preferred Units | $ 33 | $ 33 |
Redeemable noncontrolling interests | 15 | 15 |
Equity: | ||
General Partner | 306 | 184 |
Limited Partners: | ||
Common Unitholders | 17,303 | 10,430 |
Class H Unitholder | 3,464 | 1,512 |
Class I Unitholder | 15 | 0 |
Accumulated other comprehensive loss | (14) | (56) |
Total partners’ capital | 21,074 | 12,070 |
Noncontrolling interest | 5,990 | 5,153 |
Predecessor Equity | 0 | 8,088 |
Total equity | 27,064 | 25,311 |
Total liabilities and equity | $ 64,145 | $ 62,674 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
REVENUES | ||||
Natural gas sales | $ 960 | $ 1,292 | $ 2,893 | $ 4,083 |
NGL sales | 961 | 1,798 | 2,930 | 4,452 |
Crude sales | 1,859 | 4,497 | 6,747 | 13,022 |
Gathering, transportation and other fees | 1,026 | 904 | 2,999 | 2,546 |
Refined product sales | 1,046 | 5,165 | 9,136 | 14,581 |
Other | 749 | 1,277 | 3,762 | 3,364 |
Total revenues | 6,601 | 14,933 | 28,467 | 42,048 |
COSTS AND EXPENSES | ||||
Cost of products sold | 4,925 | 13,014 | 22,750 | 36,808 |
Operating expenses | 535 | 547 | 1,805 | 1,378 |
Depreciation, depletion and amortization | 471 | 410 | 1,451 | 1,206 |
Selling, general and administrative | 94 | 152 | 389 | 372 |
Total costs and expenses | 6,025 | 14,123 | 26,395 | 39,764 |
OPERATING INCOME | 576 | 810 | 2,072 | 2,284 |
OTHER INCOME (EXPENSE) | ||||
Interest expense, net of interest capitalized | (333) | (299) | (979) | (868) |
Equity in earnings of unconsolidated affiliates | 214 | 84 | 388 | 265 |
Losses on Extinguishments of Debt | (10) | 0 | (43) | 0 |
Gain on sale of AmeriGas common units | 0 | 14 | 0 | 177 |
Losses on interest rate derivatives | (64) | (25) | (14) | (73) |
Other, net | 32 | (15) | 56 | (36) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 415 | 569 | 1,480 | 1,749 |
Income tax expense (benefit) from continuing operations | 22 | 55 | (20) | 271 |
INCOME FROM CONTINUING OPERATIONS | 393 | 514 | 1,500 | 1,478 |
Income from discontinued operations | 0 | 0 | 0 | 66 |
NET INCOME | 393 | 514 | 1,500 | 1,544 |
Less: Net income (loss) attributable to noncontrolling interest | (24) | 78 | 182 | 219 |
Less: Net loss attributable to predecessor | 0 | 94 | (34) | 97 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 417 | 342 | 1,352 | 1,228 |
General Partner’s interest in net income | 277 | 135 | 779 | 373 |
Class H Unitholder’s interest in net income | 66 | 59 | 184 | 159 |
Class I Unitholder's Interest in Net Income | 15 | 0 | 80 | 0 |
Common Unitholders’ interest in net income | $ 59 | $ 148 | $ 309 | $ 696 |
INCOME FROM CONTINUING OPERATIONS PER COMMON UNIT: | ||||
Basic | $ 0.11 | $ 0.44 | $ 0.70 | $ 1.91 |
Diluted | 0.10 | 0.44 | 0.68 | 1.90 |
NET INCOME PER COMMON UNIT: | ||||
Basic | 0.11 | 0.44 | 0.70 | 2.11 |
Diluted | $ 0.10 | $ 0.44 | $ 0.68 | $ 2.10 |
Consolidated Statements Of Comp
Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ 393 | $ 514 | $ 1,500 | $ 1,544 |
Other comprehensive income (loss), net of tax: | ||||
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges | 0 | 0 | 0 | 6 |
Change in value of derivative instruments accounted for as cash flow hedges | 0 | 3 | 1 | (3) |
Change in value of available-for-sale securities | (1) | 1 | (1) | 1 |
Actuarial gain (loss) relating to pension and other postretirement benefit plans | 0 | (1) | 45 | (2) |
Foreign currency translation adjustments | 1 | (1) | (1) | (3) |
Change in other comprehensive income from unconsolidated affiliates | 0 | 0 | (2) | (6) |
Total other comprehensive income (loss) | 0 | 2 | 42 | (7) |
Comprehensive income | 393 | 516 | 1,542 | 1,537 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | (24) | 78 | 182 | 219 |
Comprehensive loss attributable to predecessor | 0 | 94 | (34) | 97 |
Comprehensive income attributable to partners | $ 417 | $ 344 | $ 1,394 | $ 1,221 |
Consolidated Statement Of Equit
Consolidated Statement Of Equity - 9 months ended Sep. 30, 2015 - USD ($) $ in Millions | Total | General Partner | Common Units | Class H Units | Class I Units | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interest | Predecessor Equity |
Balance, December 31, 2014 at Dec. 31, 2014 | $ 25,311 | $ 184 | $ 10,430 | $ 1,512 | $ 0 | $ (56) | $ 5,153 | $ 8,088 |
Distributions to partners | 2,253 | 658 | 1,352 | 178 | 65 | 0 | 0 | 0 |
Predecessor distributions to partners | (202) | 0 | 0 | 0 | 0 | 0 | 0 | (202) |
Distributions to noncontrolling interest | (247) | 0 | 0 | 0 | 0 | 0 | (247) | 0 |
Units issued for cash | 1,030 | 0 | 1,030 | 0 | 0 | 0 | 0 | 0 |
Subsidiary units issued for cash | 1,274 | 1 | 117 | 0 | 0 | 0 | 1,156 | 0 |
Predecessor units issued for cash | 34 | 0 | 0 | 0 | 0 | 0 | 0 | 34 |
Capital contributions from noncontrolling interest | 617 | 0 | 0 | 0 | 0 | 0 | 617 | 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 of noncontrolling interest | (65) | 0 | (26) | 0 | 0 | 0 | (39) | 0 |
Other comprehensive income, net of tax | 42 | 0 | 0 | 0 | 0 | 42 | 0 | 0 |
Other, net | 64 | 0 | 24 | 0 | 0 | 0 | 36 | 4 |
Net income | 1,500 | 779 | 309 | 184 | 80 | 0 | 182 | (34) |
Balance, September 30, 2015 at Sep. 30, 2015 | $ 27,064 | $ 306 | $ 17,303 | $ 3,464 | $ 15 | $ (14) | $ 5,990 | $ 0 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
OPERATING ACTIVITIES | ||
Net income | $ 1,500 | $ 1,544 |
Reconciliation of net income to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 1,451 | 1,206 |
Deferred income taxes | 22 | (65) |
Amortization included in interest expense | (30) | (48) |
Inventory valuation adjustments | (16) | 17 |
Unit-based compensation expense | 59 | 50 |
Gain on sale of AmeriGas common units | 0 | (177) |
Losses on Extinguishments of Debt | 43 | 0 |
Distributions on unvested awards | (12) | (12) |
Equity in earnings of unconsolidated affiliates | (388) | (265) |
Distributions from unconsolidated affiliates | 263 | 224 |
Other non-cash | 23 | (31) |
Cash flow in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (922) | 25 |
Net cash provided by operating activities | 1,993 | 2,468 |
INVESTING ACTIVITIES | ||
Cash proceeds from the sale of AmeriGas common units | 0 | 814 |
Cash paid for Susser Merger, net of cash received | 0 | 808 |
Cash paid for acquisition of a noncontrolling interest | (129) | 0 |
Cash transferred to ETE in connection with the Sunoco LP Exchange | (114) | 0 |
Cash paid for all other acquisitions | (475) | (985) |
Capital expenditures, excluding allowance for equity funds used during construction | (6,531) | (3,668) |
Contributions in aid of construction costs | 27 | 34 |
Contributions to unconsolidated affiliates | 75 | 271 |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 119 | 97 |
Proceeds from sale of discontinued operations | 0 | 79 |
Proceeds from the sale of assets | 20 | 22 |
Change in restricted cash | 10 | 162 |
Other | (14) | (11) |
Net cash used in investing activities | (5,151) | (4,535) |
FINANCING ACTIVITIES | ||
Proceeds from borrowings | 14,808 | 9,224 |
Repayments of long-term debt | (11,620) | (7,260) |
Units issued for cash | 1,030 | 1,126 |
Subsidiary equity offerings, net of issue costs | 1,274 | 593 |
Predecessor units issued for cash | 34 | 962 |
Capital contributions from noncontrolling interest | 583 | 19 |
Distributions to partners | 2,253 | |
Payments of Capital Distribution | (2,253) | (1,430) |
Predecessor distributions to partners | (202) | (446) |
Distributions to noncontrolling interest | (247) | (169) |
Debt issuance costs | (54) | (47) |
Other | 0 | 2 |
Net cash provided by financing activities | 3,353 | 2,574 |
Increase in cash and cash equivalents | 195 | 507 |
Cash and cash equivalents, beginning of period | 663 | 568 |
Cash and cash equivalents, end of period | 858 | 1,075 |
Bakken Pipeline Transaction [Member] | ||
INVESTING ACTIVITIES | ||
Cash received for sale of noncontrolling interest | 980 | 0 |
Rover Pipeline Sale [Member] | ||
INVESTING ACTIVITIES | ||
Cash received for sale of noncontrolling interest | 64 | 0 |
Susser Exchange Transaction [Member] | ||
INVESTING ACTIVITIES | ||
Cash received for sale of noncontrolling interest | $ 967 | $ 0 |
Operations And Organization
Operations And Organization | 9 Months Ended |
Sep. 30, 2015 | |
Operations And Organization [Abstract] | |
Operations And Organization | ORGANIZATION AND BASIS OF PRESENTATION Organization Energy Transfer Partners, L.P., a publicly traded Delaware master limited partnership, and its subsidiaries (collectively, the “Partnership,” “we,” “us,” “our” or “ETP”) are 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 consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below. Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows: • ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is 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. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. Subsequent to its acquisition of Regency’s 30% equity interest in Lone Star, as discussed below, ETC OLP now owns 100% of Lone Star. • ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of: • Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales. • ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline. • ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas. • CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline. • ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales. • ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle and Sunoco, Inc. operations are described as follows: • Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. • Sunoco, Inc. 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. Effective June 1, 2014, the Partnership combined certain Sunoco, Inc. retail assets with another wholly-owned subsidiary of ETP to form a limited liability company, Retail Holdings, owned by ETP and Sunoco, Inc. • Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets. • 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, ETE transferred to ETP 21 million ETP common units. 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 OLP is a limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the gathering, transportation and terminalling of oil (crude and/or condensate, a lighter oil) received from producers; and the management of coal and natural resource properties in the United States. Regency OLP focuses 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, Avalon and Granite Wash shales. Our financial statements reflect the following reportable business segments: • intrastate transportation and storage; • interstate transportation and storage; • midstream; • liquids transportation and services; • investment in Sunoco Logistics; • retail marketing; and • all other. Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements for the year ended December 31, 2014 included in Exhibit 99.1 to the Partnership’s Form 8-K filed on August 12, 2015. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. Merger with Regency. 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 will total $80 million for the year ending December 31, 2015 and $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. The following table presents the revenues and net income for the previously separate entities and the combined amounts presented herein: Three Months Ended Nine Months Ended 2015 (1) 2014 2015 (1) 2014 Revenues: Partnership $ 6,601 $ 13,618 $ 27,384 $ 38,879 Regency — 1,483 1,300 3,524 Adjustments and eliminations — (168 ) (217 ) (355 ) Combined $ 6,601 $ 14,933 $ 28,467 $ 42,048 Net income: Partnership $ 393 $ 447 $ 1,582 $ 1,519 Regency — 107 (29 ) 115 Adjustments and eliminations — (40 ) (53 ) (90 ) Combined $ 393 $ 514 $ 1,500 $ 1,544 (1) Amounts attributable to Regency subsequent to the Regency Merger on April 30, 2015 are reflected in the Partnership amounts. Use of Estimates Certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on net income or total equity. The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates. Excise Taxes The Partnership records the collection of taxes to be remitted to government authorities on a net basis except for the retail marketing segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and cost of products sold in the consolidated statements of operations, with no net impact on net income. Excise taxes collected by the retail marketing segment were $211 million and $632 million for the three months ended September 30, 2015 and 2014 , respectively, and $1.71 billion and $1.74 billion for the nine months ended September 30, 2015 and 2014 , respectively. Subsidiary Common Unit Transactions. The Partnership accounts for the difference between the carrying amount of its investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by Sunoco Logistics (excluding transactions with us) as capital transactions. Recent Accounting Pronouncement. 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 consolidations 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 is permitted. The Partnership expects to adopt this standard for the year ending December 31, 2016, and we are currently evaluating the impact that it will have on the consolidated financial statements and related disclosures. |
Acquisitions, Divestitures and
Acquisitions, Divestitures and Related Transactions | 9 Months Ended |
Sep. 30, 2015 | |
Acquisitions and Dispositions [Abstract] | |
Acquisitions And Divestitures | ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS 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. In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid approximately $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at approximately $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) approximately 11 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into approximately 11 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and approximately 11 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed, transferred, assigned and conveyed its interests in Susser to one of its subsidiaries. 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, ETE transferred to ETP 21 million ETP common units (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 26.8 million Sunoco LP common units and 10.9 million Sunoco LP subordinated 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 due to the continuing involvement among the entities. 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 Partnership 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, will be 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 previously announced pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast (the “Bakken Pipeline Project”). 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. Discontinued Operations Discontinued operations for the nine months ended September 30, 2014 include the results of operations for a marketing business that was sold effective April 1, 2014. |
Cash And Cash Equivalents
Cash And Cash Equivalents | 9 Months Ended |
Sep. 30, 2015 | |
Cash and Cash Equivalents [Abstract] | |
Cash And Cash Equivalents | CASH AND CASH EQUIVALENTS Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. The net change in operating assets and liabilities, net of acquisitions and deconsolidations, included in cash flows from operating activities is comprised as follows: Nine Months Ended 2015 2014 Accounts receivable $ 523 $ (782 ) Accounts receivable from related companies (467 ) (40 ) Inventories (239 ) 177 Exchanges receivable 5 4 Other current assets (101 ) 59 Other non-current assets, net 116 (23 ) Accounts payable (988 ) 512 Accounts payable to related companies 75 (10 ) Exchanges payable (97 ) (14 ) Accrued and other current liabilities 122 157 Other non-current liabilities 47 (52 ) Derivative assets and liabilities, net 82 37 Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (922 ) $ 25 Non-cash investing and financing activities are as follows: Nine Months Ended 2015 2014 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 963 $ 399 Net gains from subsidiary common unit issuances 118 81 NON-CASH FINANCING ACTIVITIES: Contribution of property, plant and equipment from noncontrolling interest $ 34 $ — Issuance of common units in connection with the Regency Merger 9,250 — Issuance of common units in connection with the Susser Merger — 908 Issuance of Class H Units in connection with the Bakken Pipeline Transaction 1,946 — Predecessor equity issuances of common units in connection with Regency’s acquisitions — 4,281 Long-term debt assumed in Regency’s acquisitions — 1,887 Long-term debt exchanged in Regency’s acquisitions — 499 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 |
Inventories
Inventories | 9 Months Ended |
Sep. 30, 2015 | |
Inventory, Gross [Abstract] | |
Inventories | INVENTORIES Inventories consisted of the following: September 30, 2015 December 31, 2014 Natural gas and NGLs $ 426 $ 392 Crude oil 461 364 Refined products 95 392 Other 241 312 Total inventories $ 1,223 $ 1,460 We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASURES We have commodity derivatives, interest rate derivatives and embedded derivatives in the 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 Preferred Units were 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 nine months ended September 30, 2015 , no transfers were made between any levels within the fair value hierarchy. Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of September 30, 2015 was $26.08 billion and $27.45 billion , respectively. As of December 31, 2014 , the aggregate fair value and carrying amount of our consolidated debt obligations was $26.91 billion and $25.98 billion , respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. 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 September 30, 2015 and December 31, 2014 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 22 $ — $ 22 $ — Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 5 5 — — Swing Swaps IFERC 4 4 — — Fixed Swaps/Futures 237 237 — — Forward Physical Swaps 2 — 2 — Power: Forwards 11 — 11 — Futures 2 2 — — Natural Gas Liquids – Forwards/Swaps 57 57 — — Refined Products – Futures 25 25 — — Crude – Futures 1 1 — — Total commodity derivatives 344 331 13 — Total assets $ 366 $ 331 $ 35 $ — Liabilities: Interest rate derivatives $ (183 ) $ — $ (183 ) $ — Embedded derivatives in the ETP Preferred Units (6 ) — — (6 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (4 ) (4 ) — — Swing Swaps IFERC (5 ) (5 ) — — Fixed Swaps/Futures (189 ) (189 ) — — Power: Forwards (12 ) — (12 ) — Futures (1 ) (1 ) — — Natural Gas Liquids – Forwards/Swaps (44 ) (44 ) — — Refined Products – Futures (1 ) (1 ) — — Total commodity derivatives (256 ) (244 ) (12 ) — Total liabilities $ (445 ) $ (244 ) $ (195 ) $ (6 ) Fair Value Measurements at Fair Value Total 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 Regency 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 ) 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 nine months ended September 30, 2015 . Balance, December 31, 2014 $ (16 ) Net unrealized gains included in other income (expense) 10 Balance, September 30, 2015 $ (6 ) |
Net Income Per Limited Partner
Net Income Per Limited Partner Unit | 9 Months Ended |
Sep. 30, 2015 | |
Earnings Per Share [Abstract] | |
Earnings Per Share [Text Block] | NET INCOME PER LIMITED PARTNER UNIT 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 the General Partner, the holder of the IDRs pursuant to the 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. Earnings attributable to predecessor represents amounts allocated to the former Regency partners and have no impact on income from continuing operations per unit for the periods prior to the Regency Merger. A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows: Three Months Ended Nine Months Ended 2015 2014 2015 2014 Income from continuing operations $ 393 $ 514 $ 1,500 $ 1,478 Less: Income (loss) from continuing operations attributable to noncontrolling interest (24 ) 78 182 219 Less: Income (loss) from continuing operations attributable to predecessor — 94 (34 ) 97 Income from continuing operations, net of noncontrolling interest and predecessor income 417 342 1,352 1,162 General Partner’s interest in income from continuing operations 277 135 779 373 Class H Unitholder’s interest in income from continuing operations 66 59 184 159 Class I Unitholder’s interest in income from continuing operations 15 — 80 — Common Unitholders’ interest in income from continuing operations 59 148 309 630 Additional earnings allocated to General Partner (3 ) — (7 ) (2 ) Distributions on employee unit awards, net of allocation to General Partner (4 ) (3 ) (11 ) (9 ) Income from continuing operations available to Common Unitholders $ 52 $ 145 $ 291 $ 619 Weighted average Common Units – basic 485.0 331.4 415.1 324.8 Basic income from continuing operations per Common Unit $ 0.11 $ 0.44 $ 0.70 $ 1.91 Income from continuing operations available to Common Unitholders $ 52 $ 145 $ 291 $ 619 Income attributable to Preferred Units (4 ) — (5 ) — Diluted income from continuing operations available to Common Unitholders $ 48 $ 145 $ 286 $ 619 Weighted average Common Units – basic 485.0 331.4 415.1 324.8 Dilutive effect of unvested employee unit awards 1.4 1.7 1.7 1.6 Dilutive effect of Preferred Units 0.9 — 0.9 — Weighted average Common Units - diluted 487.3 333.1 417.7 326.4 Diluted income from continuing operations per Common Unit $ 0.10 $ 0.44 $ 0.68 $ 1.90 Basic income from discontinued operations per Common Unit $ 0.00 $ 0.00 $ 0.00 $ 0.20 Diluted income from discontinued operations per Common Unit $ 0.00 $ 0.00 $ 0.00 $ 0.20 |
Debt Obligations
Debt Obligations | 9 Months Ended |
Sep. 30, 2015 | |
Debt Disclosure [Abstract] | |
Debt Obligations | DEBT OBLIGATIONS Our debt obligations consist of the following: September 30, 2015 December 31, 2014 ETP Senior Notes $ 19,440 $ 10,890 Transwestern Senior Notes 782 782 Panhandle Senior Notes 1,085 1,085 Sunoco, Inc. Senior Notes 465 715 Sunoco Logistics Senior Notes (1) 3,975 3,975 Regency Senior Notes (2) — 5,089 Revolving credit facilities: ETP $3.75 billion Revolving Credit Facility due November 2019 665 570 Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility due April 2015 (3) — 35 Sunoco Logistics $2.5 billion Revolving Credit Facility due March 2020 835 150 Sunoco LP $1.5 billion Revolving Credit Facility due September 2019 (5) — 683 Regency $2.5 billion Revolving Credit Facility due November 25, 2019 (4) — 1,504 Other long-term debt 31 223 Unamortized premiums, net of discounts and fair value adjustments 172 280 Total debt 27,450 25,981 Less: Current maturities of long-term debt 1 1,008 Long-term debt, less current maturities $ 27,449 $ 24,973 (1) Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of September 30, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. (2) As discussed below, the Regency senior notes were redeemed and/or assumed by the Partnership. (3) Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility matured in April 2015 and was repaid with borrowings from the Sunoco Logistics $2.5 billion Revolving Credit Facility. (4) On April 30, 2015, in connection with the Regency Merger, the Regency Credit Facility was paid off in full and terminated. (5) In connection with ETE’s acquisition of Sunoco GP, the general partner of Sunoco LP, on July 1, 2015, ETP deconsolidated Sunoco LP. The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $172 million in unamortized premiums and fair value adjustments: 2015 (remainder) $ 1 2016 375 2017 1,182 2018 2,485 2019 1,666 Thereafter 21,569 Total $ 27,278 ETP Senior Notes 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 Regency indentures 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 approximately $40 million and the amount paid to redeem the 2021 Notes included a make whole premium of approximately $24 million . Revolving 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, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. As of September 30, 2015 , the ETP Credit Facility had $665 million of outstanding borrowings. Sunoco Logistics Credit Facilities In March 2015, Sunoco Logistics amended and restated its $1.5 billion unsecured credit facility, which was scheduled to mature in November 2018. The amended and restated credit facility is a $2.5 billion unsecured revolving credit agreement (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 increased to $3.25 billion under certain conditions. As of September 30, 2015 , the Sunoco Logistics Credit Facility had $835 million of outstanding borrowings. Compliance with Our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, 2015 . |
Series A Preferred Units (Notes
Series A Preferred Units (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Series A Preferred Units [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 September 30, 2015 , the Preferred Units were convertible into 0.9 million ETP Common Units. |
Redeemable Noncontrolling Inter
Redeemable Noncontrolling Interests (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Redeemable Noncontrolling Interests [Abstract] | |
Redeemable Noncontrolling Interest [Table 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 sheets. |
Equity
Equity | 9 Months Ended |
Sep. 30, 2015 | |
Partners' Capital Notes [Abstract] | |
Equity | EQUITY Class H Units and Class I Units 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. 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 the Partnership. These IDR subsidies, including the impact from distributions on Class I Units, will be reduced by $55 million in 2015 and $30 million in 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, ETE transferred to ETP 21 million ETP common units. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years , which would terminate 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. 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.” ETP Common Unit Activity The changes in common units during the nine months ended September 30, 2015 were as follows: Number of Units Number of common units at December 31, 2014 355.5 Common units issued in connection with Equity Distribution Agreements 14.5 Common units issued in connection with the Distribution Reinvestment Plan 5.0 Common units issued in connection with the Regency Merger 172.2 Common units redeemed in connection with the Bakken Pipeline Transaction (30.8 ) Common units redeemed in connection with the Sunoco LP Exchange (21.0 ) Issuance of common units under equity incentive plans 0.2 Number of common units at September 30, 2015 495.6 During the nine months ended September 30, 2015 , the Partnership received proceeds of $775 million , net of commissions of $8 million , from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes. As of September 30, 2015 , $624 million of the Partnership’s common units remained available to be issued under an equity distribution agreement. During the nine months ended September 30, 2015 , distributions of $255 million were reinvested under the Distribution Reinvestment Plan resulting in the issuance of 5.0 million common units. As of September 30, 2015 , a total of 2.3 million common units remain available to be issued under the existing registration statement in connection with the Distribution Reinvestment Plan. Sales of Common Units by Sunoco Logistics 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 . During the nine months ended September 30, 2015 , Sunoco Logistics received proceeds of $645 million , net of commissions of $7 million , which were used for general partnership purposes. Additionally, Sunoco Logistics completed a public offering of 13.5 million common units for net proceeds of $547 million in March 2015. The net 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. As a result of Sunoco Logistics’ issuances of commo n units during the nine months ended September 30, 2015 , the Partnership recognized increases in partners’ capital of $118 million . Quarterly Distributions of Available Cash Following are distributions declared and/or paid by the Partnership subsequent to December 31, 2014 : Quarter Ended Record Date Payment Date Rate 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 ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units. Total Year 2015 (remainder) $ 28 2016 137 2017 128 2018 105 2019 95 Sunoco Logistics Quarterly Distributions of Available Cash Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2014 : Quarter Ended Record Date Payment Date Rate 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 Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: September 30, 2015 December 31, 2014 Available-for-sale securities $ 2 $ 3 Foreign currency translation adjustment (4 ) (3 ) Net loss on commodity related hedges — (1 ) Actuarial loss related to pensions and other postretirement benefits (12 ) (57 ) Investments in unconsolidated affiliates, net — 2 Total AOCI, net of tax $ (14 ) $ (56 ) |
Income Taxes (Notes)
Income Taxes (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | INCOME TAXES For the three and nine months ended September 30, 2015 , the Partnership’s effective income tax rate decreased from the prior year primarily due to lower earnings among the Partnership’s consolidated corporate subsidiaries. The three and nine months ended September 30, 2015 also reflect a benefit of $24 million of net state tax benefit attributable to statutory state rate changes resulting from the Regency Merger and sale of Susser to Sunoco LP. For the three and nine months ended September 30, 2015 , the Partnership’s income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015. Additionally, the Partnership recognized a net tax benefit of $7 million related to the settlement of the Southern Union 2004-2009 Internal Revenue Service (“IRS”) examination in July 2015. For the three and nine months ended September 30, 2014 , the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $87 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes. |
Regulatory Matters, Commitments
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | 9 Months Ended |
Sep. 30, 2015 | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | 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 purchasers. 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 has agreed to fully and unconditionally guarantee all payment obligations of Regency for all of its outstanding senior notes. 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 the 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. The settlement is subject to FERC approval. 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: Three Months Ended Nine Months Ended 2015 2014 2015 2014 Rental expense (1) $ 35 $ 31 $ 141 $ 90 Less: Sublease rental income (3 ) (9 ) (15 ) (27 ) Rental expense, net $ 32 $ 22 $ 126 $ 63 (1) Includes contingent rentals totaling $9 million and $8 million for the three months ended September 30, 2015 and 2014 and $19 million and $17 million for the nine months ended September 30, 2015 and 2014 , respectively. 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. 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 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. Each of the remaining lawsuits is at a preliminary stage. ETP cannot predict the outcome of these or any other lawsuits that might be filed, nor can we predict the amount of time and expense that will be required to resolve these lawsuits. ETP and the other defendants named in the lawsuits intend to defend vigorously against these and any other actions. 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 primarily assert 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 September 30, 2015 , Sunoco, Inc. is a defendant in six cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, 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 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 August 2015, the State of Rhode Island served a Notice of Intent to Sue on Sunoco, Inc., and certain predecessors and subsidiaries. The State of Rhode Island alleges Sunoco, Inc. unlawfully released MTBE from underground storage tanks and failed to remediate MTBE contamination in violation of various state and federal regulations. 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. 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 approximately $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. 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 September 30, 2015 and December 31, 2014 , accruals of approximately $38 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 September 30, 2015 or December 31, 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. Environmental Matters Our operations are subject to extensive federal, 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 remedial obligations, the issuance of injunctions 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 September 30, 2015 , Sunoco, Inc. had been named as a PRP at approximately 52 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. September 30, 2015 December 31, 2014 Current $ 48 $ 41 Non-current 327 360 Total environmental liabilities $ 375 $ 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 three months ended September 30, 2015 and 2014 , Sunoco, Inc. recorded $9 million and $10 million , respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2015 and 2014 , Sunoco, Inc. recorded $27 million of expenditures related to environmental cleanup programs. On June 29, 2011, the U.S. Environmental Protection Agency finalized a rule under the Clean Air Act that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future. Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures. Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances. |
Derivative Assets And Liabiliti
Derivative Assets And Liabilities | 9 Months Ended |
Sep. 30, 2015 | |
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |
Price Risk Management 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 inject and hold natural gas in our Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges 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. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas. We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. We use financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statements of operations. We are also exposed to commodity price risk on NGLs and residue gas 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 NGLs. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations. We may use derivatives in our liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGLs. Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products, crude and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Sunoco Logistics does not designate any of its derivative contracts as hedges for accounting purposes. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period. We also use derivatives to hedge a variety of price risks in our retail marketing segment. Futures and swaps are used 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. The derivatives used in our retail marketing segment represent economic hedges; however, we have elected not to designate any of these derivative contracts as hedges in this business segment. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period. Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, 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: September 30, 2015 December 31, 2014 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures 2,750,700 2015-2016 (232,500 ) 2015 Basis Swaps IFERC/NYMEX (1) 32,677,500 2015-2016 (13,907,500 ) 2015-2016 Options – Calls — — 5,000,000 2015 Power (Megawatt): Forwards 557,220 2015-2016 288,775 2015 Futures (846,164 ) 2015-2016 (156,000 ) 2015 Options – Puts (11,361 ) 2015 (72,000 ) 2015 Options – Calls (55,618 ) 2015 198,556 2015 Crude (Bbls) – Futures (140,000 ) 2015 — — (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (6,872,500 ) 2015-2016 57,500 2015 Swing Swaps IFERC 73,757,500 2015-2016 46,150,000 2015 Fixed Swaps/Futures (17,292,500 ) 2015-2016 (34,304,000 ) 2015-2016 Forward Physical Contracts (1,537,218 ) 2015 (9,116,777 ) 2015 Natural Gas Liquid and Crude (Bbls) – Forwards/Swaps (6,138,800 ) 2015-2016 (4,417,400 ) 2015-2016 Refined Products (Bbls) – Futures (2,273,000 ) 2015-2016 13,745,755 2015 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. Regency previously had swap contracts that settled against certain NGLs, condensate and natural gas market prices. In April 2015, in connection with the Regency Merger, Regency settled all outstanding swap contracts and received net proceeds of $56 million . Interest Rate Risk We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances. The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding September 30, 2015 December 31, 2014 July 2015 (2) Forward-starting to pay a fixed rate of 3.40% 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 3-month LIBOR and receive a fixed rate of 1.53% 1,200 — March 2019 Pay a floating rate based on 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. These forward-starting swaps matured in July 2015. (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. We also implement the use of industry standard commercial agreements which allow for the netting of positive and negative 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, motor fuel distributors, municipalities, gas and electric utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic factors 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. We have 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 September 30, 2015 December 31, 2014 September 30, 2015 December 31, 2014 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 18 $ 43 $ (1 ) $ — 18 43 (1 ) — Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 313 617 (243 ) (577 ) Commodity derivatives 13 107 (12 ) (23 ) Interest rate derivatives 22 3 (183 ) (155 ) Embedded derivatives in ETP Preferred Units — — (6 ) (16 ) 348 727 (444 ) (771 ) Total derivatives $ 366 $ 770 $ (445 ) $ (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 September 30, 2015 December 31, 2014 September 30, 2015 December 31, 2014 Derivatives without offsetting agreements $ 22 $ 3 $ (189 ) $ (171 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) $ 13 $ 107 $ (12 ) $ (23 ) Broker cleared derivative contracts Other current assets 331 660 (244 ) (577 ) Total gross derivatives 366 770 (445 ) (771 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (10 ) (19 ) 10 19 Counterparty netting Other current assets (244 ) (577 ) 244 577 Total net derivatives $ 112 $ 174 $ (191 ) $ (175 ) We disclose the non-exchange traded financial derivative instruments as price risk management 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) Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ 3 $ 1 $ (3 ) Total $ — $ 3 $ 1 $ (3 ) Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ — $ — $ (6 ) Total $ — $ — $ — $ (6 ) Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ (1 ) $ 1 $ 7 $ (5 ) Total $ (1 ) $ 1 $ 7 $ (5 ) Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (2 ) $ (4 ) $ (10 ) $ (2 ) Commodity derivatives – Non-trading Cost of products sold 48 52 — 9 Interest rate derivatives Losses on interest rate derivatives (64 ) (25 ) (14 ) (73 ) Embedded derivatives Other expense 6 (1 ) 10 (11 ) Total $ (12 ) $ 22 $ (14 ) $ (77 ) |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 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. After the deconsolidation of Sunoco LP, ETP’s transactions with Sunoco LP are now reflected as related party transactions. ETP purchased motor fuels from Sunoco LP totaling $500 million for the three months ended September 30, 2015 . 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: Three Months Ended Nine Months Ended 2015 2014 2015 2014 Affiliated revenues $ 94 $ 262 $ 300 $ 951 The following table summarizes the related company balances on our consolidated balance sheets: September 30, 2015 December 31, 2014 Accounts receivable from related companies: ETE $ 135 $ 11 PES 12 6 FGT 77 9 Lake Charles LNG 4 3 Trans-Pecos Pipeline, LLC 50 — Comanche Trail Pipeline, LLC 72 — Other 78 110 Total accounts receivable from related companies: $ 428 $ 139 Accounts payable to related companies: Sunoco LP $ 230 $ — PES 5 — FGT — 2 Lake Charles LNG 3 2 Trans-Pecos Pipeline, LLC 4 — Other 14 21 Total accounts payable to related companies: $ 256 $ 25 |
Other Information
Other Information | 9 Months Ended |
Sep. 30, 2015 | |
Other Information [Abstract] | |
Other Information | OTHER INFORMATION The following tables present additional detail for certain balance sheet captions. Other Current Assets Other current assets consisted of the following: September 30, 2015 December 31, 2014 Deposits paid to vendors $ 99 $ 65 Deferred income taxes — 14 Income taxes receivable 99 17 Prepaid expenses and other 157 200 Total other current assets $ 355 $ 296 Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: September 30, 2015 December 31, 2014 Interest payable $ 389 $ 382 Customer advances and deposits 105 103 Accrued capital expenditures 821 673 Accrued wages and benefits 200 233 Taxes payable other than income taxes 202 236 Income taxes payable — 54 Deferred income taxes 99 99 Other 284 319 Total accrued and other current liabilities $ 2,100 $ 2,099 |
Reportable Segments
Reportable Segments | 9 Months Ended |
Sep. 30, 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, losses on extinguishments 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: Three Months Ended Nine Months Ended 2015 2014 2015 2014 Revenues: Intrastate transportation and storage: Revenues from external customers $ 477 $ 557 $ 1,504 $ 2,069 Intersegment revenues 115 44 243 178 592 601 1,747 2,247 Interstate transportation and storage: Revenues from external customers 245 254 755 794 Intersegment revenues 3 4 12 11 248 258 767 805 Midstream: Revenues from external customers 543 1,358 2,067 3,707 Intersegment revenues 840 609 1,715 1,517 1,383 1,967 3,782 5,224 Liquids transportation and services: Revenues from external customers 779 1,148 2,366 2,807 Intersegment revenues 75 48 143 122 854 1,196 2,509 2,929 Investment in Sunoco Logistics: Revenues from external customers 2,379 4,862 8,026 14,080 Intersegment revenues 27 53 155 133 2,406 4,915 8,181 14,213 Retail marketing: Revenues from external customers 1,362 5,985 11,701 16,561 Intersegment revenues 1 3 4 6 1,363 5,988 11,705 16,567 All other: Revenues from external customers 816 769 2,048 2,030 Intersegment revenues 160 128 391 352 976 897 2,439 2,382 Eliminations (1,221 ) (889 ) (2,663 ) (2,319 ) Total revenues $ 6,601 $ 14,933 $ 28,467 $ 42,048 Three Months Ended Nine Months Ended 2015 2014 2015 2014 Segment Adjusted EBITDA: Intrastate transportation and storage $ 127 $ 124 $ 421 $ 439 Interstate transportation and storage 286 288 872 905 Midstream 318 379 986 958 Liquids transportation and services 192 163 509 432 Investment in Sunoco Logistics 289 246 836 734 Retail marketing 195 191 464 436 All other 93 60 266 278 Total 1,500 1,451 4,354 4,182 Depreciation, depletion and amortization (471 ) (410 ) (1,451 ) (1,206 ) Interest expense, net of interest capitalized (333 ) (299 ) (979 ) (868 ) Gain on sale of AmeriGas common units — 14 — 177 Losses on interest rate derivatives (64 ) (25 ) (14 ) (73 ) Non-cash unit-based compensation expense (16 ) (18 ) (59 ) (50 ) Unrealized gains (losses) on commodity risk management activities 47 32 (72 ) (1 ) Inventory valuation adjustments (134 ) (51 ) 16 (17 ) Losses on extinguishments of debt (10 ) — (43 ) — Adjusted EBITDA related to discontinued operations — — — (27 ) Adjusted EBITDA related to unconsolidated affiliates (350 ) (184 ) (711 ) (584 ) Equity in earnings of unconsolidated affiliates 214 84 388 265 Other, net 32 (25 ) 51 (49 ) Income from continuing operations before income tax expense $ 415 $ 569 $ 1,480 $ 1,749 September 30, 2015 December 31, 2014 Assets: Intrastate transportation and storage $ 4,889 $ 4,984 Interstate transportation and storage 10,518 10,779 Midstream 16,886 15,562 Liquids transportation and services 7,030 4,568 Investment in Sunoco Logistics 14,586 13,619 Retail marketing 3,173 8,930 All other 7,063 4,232 Total assets $ 64,145 $ 62,674 |
Consolidating Guarantor Financi
Consolidating Guarantor Financial Information (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Guarantees [Abstract] | |
Guarantees [Text Block] | CONSOLIDATING GUARANTOR FINANCIAL INFORMATION 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 outstanding senior notes of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor. ELG, Aqua – PVR and ORS do not fully and unconditionally guarantee, on a joint and several basis, the Regency senior notes. Included in the Parent financial statements are the Partnership’s intercompany investments in all consolidated subsidiaries. Included in the Issuer financial statements are Regency’s intercompany investments in all consolidated subsidiaries and Regency’s investments in unconsolidated affiliates. ELG, Aqua – PVR and ORS are included in the non-guarantor subsidiaries, as well as the unconsolidated subsidiaries of ETP. The consolidating financial information for the Parent, Issuer, Guarantor Subsidiaries, and Non-Guarantor Subsidiaries are as follows: September 30, 2015 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash and cash equivalents $ (1 ) $ — $ (14 ) $ 880 $ (7 ) $ 858 All other current assets 4,243 — 541 (317 ) — 4,467 Property, plant, and equipment, net 171 — 9,402 33,328 (80 ) 42,821 Investments in subsidiaries 40,498 — 682 — (41,180 ) — Investments in unconsolidated affiliates 23 — 979 3,865 252 5,119 All other assets 2,335 — 4,529 4,016 — 10,880 Total assets $ 47,269 $ — $ 16,119 $ 41,772 $ (41,015 ) $ 64,145 Current liabilities 395 — 1,113 2,979 (4 ) 4,483 Non-current liabilities 20,889 — 63 11,646 — 32,598 Noncontrolling interest — — — 5,782 208 5,990 Total partners’ capital 25,985 — 14,943 21,365 (41,219 ) 21,074 Total liabilities and equity $ 47,269 $ — $ 16,119 $ 41,772 $ (41,015 ) $ 64,145 December 31, 2014 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash and cash equivalents $ 17 $ — $ — $ 654 $ (8 ) $ 663 All other current assets 273 — 667 4,587 (147 ) 5,380 Property, plant, and equipment, net 103 — 8,948 30,094 (238 ) 38,907 Investments in subsidiaries 24,361 19,829 — 6,755 (50,945 ) — Investments in unconsolidated affiliates 63 — 2,252 2,441 (996 ) 3,760 All other assets 3,826 — 4,765 10,047 (4,674 ) 13,964 Total assets $ 28,643 $ 19,829 $ 16,632 $ 54,578 $ (57,008 ) $ 62,674 Current liabilities 1,117 — 723 5,073 (229 ) 6,684 Non-current liabilities 11,561 5,185 1,575 16,952 (4,594 ) 30,679 Noncontrolling interest — — — 60 5,093 5,153 Predecessor equity — 14,644 14,334 358 (21,248 ) 8,088 Total partners’ capital 15,965 — — 32,135 (36,030 ) 12,070 Total liabilities and equity $ 28,643 $ 19,829 $ 16,632 $ 54,578 $ (57,008 ) $ 62,674 Three Months Ended September 30, 2015 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 909 $ 5,682 $ 10 $ 6,601 Operating costs, expenses, and other (6 ) — 894 5,129 8 6,025 Operating income 6 — 15 553 2 576 Interest expense, net (264 ) (23 ) 6 (91 ) 39 (333 ) Equity in earnings of unconsolidated affiliates 504 — 25 128 (443 ) 214 Losses on extinguishments of debt (9 ) (1 ) — — — (10 ) Losses on interest rate derivatives (64 ) — — — — (64 ) Other, net 251 — 1 (182 ) (38 ) 32 Income (loss) before income taxes 424 (24 ) 47 408 (440 ) 415 Income tax expense (benefit) 7 (1 ) — 16 — 22 Income (loss) from continuing operations 417 (23 ) 47 392 (440 ) 393 Net income (loss) 417 (23 ) 47 392 (440 ) 393 Less: Net loss attributable to noncontrolling interest — — — (40 ) 16 (24 ) Net income (loss) attributable to partners $ 417 $ (23 ) $ 47 $ 432 $ (456 ) $ 417 Other comprehensive income $ — $ — $ — $ 84 $ (84 ) $ — Comprehensive income (loss) 417 (23 ) 47 476 (524 ) 393 Comprehensive loss attributable to noncontrolling interest — — — (40 ) 16 (24 ) Comprehensive income (loss) attributable to partners $ 417 $ (23 ) $ 47 $ 516 $ (540 ) $ 417 Three Months Ended September 30, 2014 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 1,467 $ 13,468 $ (2 ) $ 14,933 Operating costs, expenses, and other (17 ) — 1,334 12,810 (4 ) 14,123 Operating income 17 — 133 658 2 810 Interest expense, net (172 ) (85 ) (1 ) (95 ) 54 (299 ) Equity in earnings (losses) of unconsolidated affiliates 474 327 20 (139 ) (598 ) 84 Gain on sale of AmeriGas common units 14 — — — — 14 Losses on interest rate derivatives (25 ) — — — — (25 ) Other, net 42 1 — (5 ) (53 ) (15 ) Income before income taxes 350 243 152 419 (595 ) 569 Income tax expense 10 2 2 41 — 55 Income from continuing operations 340 241 150 378 (595 ) 514 Income from discontinued operations — — 32 — (32 ) — Net income 340 241 182 378 (627 ) 514 Less: Net income attributable to noncontrolling interest — — — 74 4 78 Less: Net loss attributable to predecessor — — — 94 — 94 Net income attributable to partners $ 340 $ 241 $ 182 $ 210 $ (631 ) $ 342 Other comprehensive income (loss) $ 2 $ — $ — $ (16 ) $ 16 $ 2 Comprehensive income 342 241 182 362 (611 ) 516 Comprehensive income attributable to noncontrolling interest — — — 74 4 78 Comprehensive income attributable to predecessor — — — 94 — 94 Comprehensive income attributable to partners $ 342 $ 241 $ 182 $ 194 $ (615 ) $ 344 Nine Months Ended September 30, 2015 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 2,778 $ 25,691 $ (2 ) $ 28,467 Operating costs, expenses, and other (25 ) 1 2,758 23,666 (5 ) 26,395 Operating income (loss) 25 (1 ) 20 2,025 3 2,072 Interest expense, net (622 ) (173 ) 7 (331 ) 140 (979 ) Equity in earnings of unconsolidated affiliates 1,245 106 69 408 (1,440 ) 388 Losses on extinguishments of debt (9 ) (22 ) (12 ) — — (43 ) Losses on interest rate derivatives (14 ) — — — — (14 ) Other, net 731 2 2 (540 ) (139 ) 56 Income (loss) before income taxes 1,356 (88 ) 86 1,562 (1,436 ) 1,480 Income tax expense (benefit) 4 (4 ) — (20 ) — (20 ) Income (loss) from continuing operations 1,352 (84 ) 86 1,582 (1,436 ) 1,500 Income from discontinued operations — — 48 — (48 ) — Net income (loss) 1,352 (84 ) 134 1,582 (1,484 ) 1,500 Less: Net income attributable to noncontrolling interest — — — 170 12 182 Less: Net loss attributable to predecessor — — — (34 ) — (34 ) Net income (loss) attributable to partners $ 1,352 $ (84 ) $ 134 $ 1,446 $ (1,496 ) $ 1,352 Other comprehensive income $ 42 $ — $ — $ 42 $ (42 ) $ 42 Comprehensive income (loss) 1,394 (84 ) 134 1,624 (1,526 ) 1,542 Comprehensive income attributable to noncontrolling interest — — — 170 12 182 Comprehensive loss attributable to predecessor — — — (34 ) — (34 ) Comprehensive income (loss) attributable to partners $ 1,394 $ (84 ) $ 134 $ 1,488 $ (1,538 ) $ 1,394 Nine Months Ended September 30, 2014 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 3,478 $ 38,573 $ (3 ) $ 42,048 Operating costs, expenses, and other (53 ) — 3,306 36,518 (7 ) 39,764 Operating income 53 — 172 2,055 4 2,284 Interest expense, net (521 ) (206 ) (14 ) (276 ) 149 (868 ) Equity in earnings of unconsolidated affiliates 1,459 327 60 181 (1,762 ) 265 Gain on sale of AmeriGas common units 177 — — — — 177 Losses on interest rate derivatives (60 ) — — (13 ) — (73 ) Other, net 124 (7 ) 3 (8 ) (148 ) (36 ) Income before income taxes 1,232 114 221 1,939 (1,757 ) 1,749 Income tax expense 4 3 — 264 — 271 Income from continuing operations 1,228 111 221 1,675 (1,757 ) 1,478 Income from discontinued operations — — 83 66 (83 ) 66 Net income 1,228 111 304 1,741 (1,840 ) 1,544 Less: Net income attributable to noncontrolling interest — — — 208 11 219 Less: Net income attributable to predecessor — — — 97 — 97 Net income attributable to partners $ 1,228 $ 111 $ 304 $ 1,436 $ (1,851 ) $ 1,228 Other comprehensive loss $ (7 ) $ — $ — $ (7 ) $ 7 $ (7 ) Comprehensive income 1,221 111 304 1,734 (1,833 ) 1,537 Comprehensive income attributable to noncontrolling interest — — — 208 11 219 Comprehensive income attributable to predecessor — — — 97 — 97 Comprehensive income attributable to partners $ 1,221 $ 111 $ 304 $ 1,429 $ (1,844 ) $ 1,221 Nine Months Ended September 30, 2015 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ (3,435 ) $ (175 ) $ 208 $ 5,593 $ (198 ) $ 1,993 Cash flows from investing activities 999 — (893 ) (5,109 ) (148 ) (5,151 ) Cash flows from financing activities 2,418 175 671 (258 ) 347 3,353 Change in cash (18 ) — (14 ) 226 1 195 Cash at beginning of period 17 — — 654 (8 ) 663 Cash at end of period $ (1 ) $ — $ (14 ) $ 880 $ (7 ) $ 858 Nine Months Ended September 30, 2014 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ 790 $ (216 ) $ 529 $ 3,063 $ (1,698 ) $ 2,468 Cash flows from investing activities (310 ) (952 ) (564 ) (2,498 ) (211 ) (4,535 ) Cash flows from financing activities (214 ) 1,168 35 (313 ) 1,898 2,574 Change in cash 266 — — 252 (11 ) 507 Cash at beginning of period — — — 568 — 568 Cash at end of period $ 266 $ — $ — $ 820 $ (11 ) $ 1,075 |
Operations And Organization Acc
Operations And Organization Accounting Policy (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Accounting Policies [Abstract] | |
Consolidation, Subsidiary Stock Issuances, Policy [Policy Text Block] | Subsidiary Common Unit Transactions. The Partnership accounts for the difference between the carrying amount of its investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by Sunoco Logistics (excluding transactions with us) as capital transactions. |
Use of Estimates, Policy [Policy Text Block] | Use of Estimates Certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on net income or total equity. The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates. |
Combination of Entities under Common Control, Policy [Policy Text Block] | 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. |
New Accounting Pronouncements, Policy [Policy Text Block] | Recent Accounting Pronouncement. 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 consolidations 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 is permitted. The Partnership expects to adopt this standard for the year ending December 31, 2016, and we are currently evaluating the impact that it will have on the consolidated financial statements and related disclosures. |
Excise Tax, Policy [Policy Text Block] | Excise Taxes The Partnership records the collection of taxes to be remitted to government authorities on a net basis except for the retail marketing segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and cost of products sold in the consolidated statements of operations, with no net impact on net income. Excise taxes collected by the retail marketing segment were $211 million and $632 million for the three months ended September 30, 2015 and 2014 , respectively, and $1.71 billion and $1.74 billion for the nine months ended September 30, 2015 and 2014 , respectively. |
Operations And Organization Com
Operations And Organization Combined Table (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Business Combinations [Abstract] | |
Business Combination, Separately Recognized Transactions [Table Text Block] | The following table presents the revenues and net income for the previously separate entities and the combined amounts presented herein: Three Months Ended Nine Months Ended 2015 (1) 2014 2015 (1) 2014 Revenues: Partnership $ 6,601 $ 13,618 $ 27,384 $ 38,879 Regency — 1,483 1,300 3,524 Adjustments and eliminations — (168 ) (217 ) (355 ) Combined $ 6,601 $ 14,933 $ 28,467 $ 42,048 Net income: Partnership $ 393 $ 447 $ 1,582 $ 1,519 Regency — 107 (29 ) 115 Adjustments and eliminations — (40 ) (53 ) (90 ) Combined $ 393 $ 514 $ 1,500 $ 1,544 (1) Amounts attributable to Regency subsequent to the Regency Merger on April 30, 2015 are reflected in the Partnership amounts. |
Cash And Cash Equivalents (Tabl
Cash And Cash Equivalents (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Cash and Cash Equivalents [Abstract] | |
Net Cash Provided By Operating Activities | The net change in operating assets and liabilities, net of acquisitions and deconsolidations, included in cash flows from operating activities is comprised as follows: Nine Months Ended 2015 2014 Accounts receivable $ 523 $ (782 ) Accounts receivable from related companies (467 ) (40 ) Inventories (239 ) 177 Exchanges receivable 5 4 Other current assets (101 ) 59 Other non-current assets, net 116 (23 ) Accounts payable (988 ) 512 Accounts payable to related companies 75 (10 ) Exchanges payable (97 ) (14 ) Accrued and other current liabilities 122 157 Other non-current liabilities 47 (52 ) Derivative assets and liabilities, net 82 37 Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (922 ) $ 25 |
Non-Cash Investing And Financing Activities | Non-cash investing and financing activities are as follows: Nine Months Ended 2015 2014 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 963 $ 399 Net gains from subsidiary common unit issuances 118 81 NON-CASH FINANCING ACTIVITIES: Contribution of property, plant and equipment from noncontrolling interest $ 34 $ — Issuance of common units in connection with the Regency Merger 9,250 — Issuance of common units in connection with the Susser Merger — 908 Issuance of Class H Units in connection with the Bakken Pipeline Transaction 1,946 — Predecessor equity issuances of common units in connection with Regency’s acquisitions — 4,281 Long-term debt assumed in Regency’s acquisitions — 1,887 Long-term debt exchanged in Regency’s acquisitions — 499 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 |
Inventories (Tables)
Inventories (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Inventory, Gross [Abstract] | |
Schedule Of Inventories | Inventories consisted of the following: September 30, 2015 December 31, 2014 Natural gas and NGLs $ 426 $ 392 Crude oil 461 364 Refined products 95 392 Other 241 312 Total inventories $ 1,223 $ 1,460 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Measurements [Abstract] | |
Fair Value Of Assets And Liabilities Measured And Recorded On Recurring Basis | 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 September 30, 2015 and December 31, 2014 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 22 $ — $ 22 $ — Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 5 5 — — Swing Swaps IFERC 4 4 — — Fixed Swaps/Futures 237 237 — — Forward Physical Swaps 2 — 2 — Power: Forwards 11 — 11 — Futures 2 2 — — Natural Gas Liquids – Forwards/Swaps 57 57 — — Refined Products – Futures 25 25 — — Crude – Futures 1 1 — — Total commodity derivatives 344 331 13 — Total assets $ 366 $ 331 $ 35 $ — Liabilities: Interest rate derivatives $ (183 ) $ — $ (183 ) $ — Embedded derivatives in the ETP Preferred Units (6 ) — — (6 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (4 ) (4 ) — — Swing Swaps IFERC (5 ) (5 ) — — Fixed Swaps/Futures (189 ) (189 ) — — Power: Forwards (12 ) — (12 ) — Futures (1 ) (1 ) — — Natural Gas Liquids – Forwards/Swaps (44 ) (44 ) — — Refined Products – Futures (1 ) (1 ) — — Total commodity derivatives (256 ) (244 ) (12 ) — Total liabilities $ (445 ) $ (244 ) $ (195 ) $ (6 ) Fair Value Measurements at Fair Value Total 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 Regency 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 ) |
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 nine months ended September 30, 2015 . Balance, December 31, 2014 $ (16 ) Net unrealized gains included in other income (expense) 10 Balance, September 30, 2015 $ (6 ) |
Net Income Per Limited Partne29
Net Income Per Limited Partner Unit (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows: Three Months Ended Nine Months Ended 2015 2014 2015 2014 Income from continuing operations $ 393 $ 514 $ 1,500 $ 1,478 Less: Income (loss) from continuing operations attributable to noncontrolling interest (24 ) 78 182 219 Less: Income (loss) from continuing operations attributable to predecessor — 94 (34 ) 97 Income from continuing operations, net of noncontrolling interest and predecessor income 417 342 1,352 1,162 General Partner’s interest in income from continuing operations 277 135 779 373 Class H Unitholder’s interest in income from continuing operations 66 59 184 159 Class I Unitholder’s interest in income from continuing operations 15 — 80 — Common Unitholders’ interest in income from continuing operations 59 148 309 630 Additional earnings allocated to General Partner (3 ) — (7 ) (2 ) Distributions on employee unit awards, net of allocation to General Partner (4 ) (3 ) (11 ) (9 ) Income from continuing operations available to Common Unitholders $ 52 $ 145 $ 291 $ 619 Weighted average Common Units – basic 485.0 331.4 415.1 324.8 Basic income from continuing operations per Common Unit $ 0.11 $ 0.44 $ 0.70 $ 1.91 Income from continuing operations available to Common Unitholders $ 52 $ 145 $ 291 $ 619 Income attributable to Preferred Units (4 ) — (5 ) — Diluted income from continuing operations available to Common Unitholders $ 48 $ 145 $ 286 $ 619 Weighted average Common Units – basic 485.0 331.4 415.1 324.8 Dilutive effect of unvested employee unit awards 1.4 1.7 1.7 1.6 Dilutive effect of Preferred Units 0.9 — 0.9 — Weighted average Common Units - diluted 487.3 333.1 417.7 326.4 Diluted income from continuing operations per Common Unit $ 0.10 $ 0.44 $ 0.68 $ 1.90 Basic income from discontinued operations per Common Unit $ 0.00 $ 0.00 $ 0.00 $ 0.20 Diluted income from discontinued operations per Common Unit $ 0.00 $ 0.00 $ 0.00 $ 0.20 |
Debt Obligations Debt Table (Ta
Debt Obligations Debt Table (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Schedule of Maturities of Long-term Debt [Table Text Block] | The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $172 million in unamortized premiums and fair value adjustments: 2015 (remainder) $ 1 2016 375 2017 1,182 2018 2,485 2019 1,666 Thereafter 21,569 Total $ 27,278 |
Schedule of Long-term Debt Instruments [Table Text Block] | Our debt obligations consist of the following: September 30, 2015 December 31, 2014 ETP Senior Notes $ 19,440 $ 10,890 Transwestern Senior Notes 782 782 Panhandle Senior Notes 1,085 1,085 Sunoco, Inc. Senior Notes 465 715 Sunoco Logistics Senior Notes (1) 3,975 3,975 Regency Senior Notes (2) — 5,089 Revolving credit facilities: ETP $3.75 billion Revolving Credit Facility due November 2019 665 570 Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility due April 2015 (3) — 35 Sunoco Logistics $2.5 billion Revolving Credit Facility due March 2020 835 150 Sunoco LP $1.5 billion Revolving Credit Facility due September 2019 (5) — 683 Regency $2.5 billion Revolving Credit Facility due November 25, 2019 (4) — 1,504 Other long-term debt 31 223 Unamortized premiums, net of discounts and fair value adjustments 172 280 Total debt 27,450 25,981 Less: Current maturities of long-term debt 1 1,008 Long-term debt, less current maturities $ 27,449 $ 24,973 (1) Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of September 30, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. (2) As discussed below, the Regency senior notes were redeemed and/or assumed by the Partnership. (3) Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility matured in April 2015 and was repaid with borrowings from the Sunoco Logistics $2.5 billion Revolving Credit Facility. (4) On April 30, 2015, in connection with the Regency Merger, the Regency Credit Facility was paid off in full and terminated. (5) In connection with ETE’s acquisition of Sunoco GP, the general partner of Sunoco LP, on July 1, 2015, ETP deconsolidated Sunoco LP. |
Equity (Tables)
Equity (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Change In Common Units | The changes in common units during the nine months ended September 30, 2015 were as follows: Number of Units Number of common units at December 31, 2014 355.5 Common units issued in connection with Equity Distribution Agreements 14.5 Common units issued in connection with the Distribution Reinvestment Plan 5.0 Common units issued in connection with the Regency Merger 172.2 Common units redeemed in connection with the Bakken Pipeline Transaction (30.8 ) Common units redeemed in connection with the Sunoco LP Exchange (21.0 ) Issuance of common units under equity incentive plans 0.2 Number of common units at September 30, 2015 495.6 |
Schedule of Net IDR Subsidies [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 2015 (remainder) $ 28 2016 137 2017 128 2018 105 2019 95 |
Accumulated Other Comprehensive Income | The following table presents the components of AOCI, net of tax: September 30, 2015 December 31, 2014 Available-for-sale securities $ 2 $ 3 Foreign currency translation adjustment (4 ) (3 ) Net loss on commodity related hedges — (1 ) Actuarial loss related to pensions and other postretirement benefits (12 ) (57 ) Investments in unconsolidated affiliates, net — 2 Total AOCI, net of tax $ (14 ) $ (56 ) |
ETP [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Following are distributions declared and/or paid by the Partnership subsequent to December 31, 2014 : Quarter Ended Record Date Payment Date Rate 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 |
Sunoco Logistics [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2014 : Quarter Ended Record Date Payment Date Rate 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 |
Regulatory Matters, Commitmen32
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
Schedule of Rent Expense [Table Text Block] | We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 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: Three Months Ended Nine Months Ended 2015 2014 2015 2014 Rental expense (1) $ 35 $ 31 $ 141 $ 90 Less: Sublease rental income (3 ) (9 ) (15 ) (27 ) Rental expense, net $ 32 $ 22 $ 126 $ 63 (1) Includes contingent rentals totaling $9 million and $8 million for the three months ended September 30, 2015 and 2014 and $19 million and $17 million for the nine months ended September 30, 2015 and 2014 , respectively. |
Environmental Exit Costs by Cost [Table Text Block] | September 30, 2015 December 31, 2014 Current $ 48 $ 41 Non-current 327 360 Total environmental liabilities $ 375 $ 401 |
Derivative Assets And Liabili33
Derivative Assets And Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Derivative [Line Items] | |
Outstanding Commodity-Related Derivatives | The following table details our outstanding commodity-related derivatives: September 30, 2015 December 31, 2014 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures 2,750,700 2015-2016 (232,500 ) 2015 Basis Swaps IFERC/NYMEX (1) 32,677,500 2015-2016 (13,907,500 ) 2015-2016 Options – Calls — — 5,000,000 2015 Power (Megawatt): Forwards 557,220 2015-2016 288,775 2015 Futures (846,164 ) 2015-2016 (156,000 ) 2015 Options – Puts (11,361 ) 2015 (72,000 ) 2015 Options – Calls (55,618 ) 2015 198,556 2015 Crude (Bbls) – Futures (140,000 ) 2015 — — (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (6,872,500 ) 2015-2016 57,500 2015 Swing Swaps IFERC 73,757,500 2015-2016 46,150,000 2015 Fixed Swaps/Futures (17,292,500 ) 2015-2016 (34,304,000 ) 2015-2016 Forward Physical Contracts (1,537,218 ) 2015 (9,116,777 ) 2015 Natural Gas Liquid and Crude (Bbls) – Forwards/Swaps (6,138,800 ) 2015-2016 (4,417,400 ) 2015-2016 Refined Products (Bbls) – Futures (2,273,000 ) 2015-2016 13,745,755 2015 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 September 30, 2015 December 31, 2014 July 2015 (2) Forward-starting to pay a fixed rate of 3.40% 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 3-month LIBOR and receive a fixed rate of 1.53% 1,200 — March 2019 Pay a floating rate based on 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. These forward-starting swaps matured in July 2015. (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 September 30, 2015 December 31, 2014 September 30, 2015 December 31, 2014 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 18 $ 43 $ (1 ) $ — 18 43 (1 ) — Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 313 617 (243 ) (577 ) Commodity derivatives 13 107 (12 ) (23 ) Interest rate derivatives 22 3 (183 ) (155 ) Embedded derivatives in ETP Preferred Units — — (6 ) (16 ) 348 727 (444 ) (771 ) Total derivatives $ 366 $ 770 $ (445 ) $ (771 ) |
Derivatives, Offsetting Fair Value Amounts [Table Text Block] | The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location September 30, 2015 December 31, 2014 September 30, 2015 December 31, 2014 Derivatives without offsetting agreements $ 22 $ 3 $ (189 ) $ (171 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) $ 13 $ 107 $ (12 ) $ (23 ) Broker cleared derivative contracts Other current assets 331 660 (244 ) (577 ) Total gross derivatives 366 770 (445 ) (771 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (10 ) (19 ) 10 19 Counterparty netting Other current assets (244 ) (577 ) 244 577 Total net derivatives $ 112 $ 174 $ (191 ) $ (175 ) |
Partnership's Derivative Assets And Liabilities | The following tables summarize the amounts recognized with respect to our derivative financial instruments: Change in Value Recognized in OCI on Derivatives (Effective Portion) Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ 3 $ 1 $ (3 ) Total $ — $ 3 $ 1 $ (3 ) |
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) Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ — $ — $ (6 ) Total $ — $ — $ — $ (6 ) |
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 Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ (1 ) $ 1 $ 7 $ (5 ) Total $ (1 ) $ 1 $ 7 $ (5 ) |
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 Three Months Ended Nine Months Ended 2015 2014 2015 2014 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (2 ) $ (4 ) $ (10 ) $ (2 ) Commodity derivatives – Non-trading Cost of products sold 48 52 — 9 Interest rate derivatives Losses on interest rate derivatives (64 ) (25 ) (14 ) (73 ) Embedded derivatives Other expense 6 (1 ) 10 (11 ) Total $ (12 ) $ 22 $ (14 ) $ (77 ) |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions For Period Presented [Table Text Block] | The following table summarizes the affiliate revenues on our consolidated statements of operations: Three Months Ended Nine Months Ended 2015 2014 2015 2014 Affiliated revenues $ 94 $ 262 $ 300 $ 951 |
Related Party Balances For Period Presented [Table Text Block] | The following table summarizes the related company balances on our consolidated balance sheets: September 30, 2015 December 31, 2014 Accounts receivable from related companies: ETE $ 135 $ 11 PES 12 6 FGT 77 9 Lake Charles LNG 4 3 Trans-Pecos Pipeline, LLC 50 — Comanche Trail Pipeline, LLC 72 — Other 78 110 Total accounts receivable from related companies: $ 428 $ 139 Accounts payable to related companies: Sunoco LP $ 230 $ — PES 5 — FGT — 2 Lake Charles LNG 3 2 Trans-Pecos Pipeline, LLC 4 — Other 14 21 Total accounts payable to related companies: $ 256 $ 25 |
Other Information (Tables)
Other Information (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Other Information [Abstract] | |
Other Current Assets | Other current assets consisted of the following: September 30, 2015 December 31, 2014 Deposits paid to vendors $ 99 $ 65 Deferred income taxes — 14 Income taxes receivable 99 17 Prepaid expenses and other 157 200 Total other current assets $ 355 $ 296 |
Accrued And Other Current Liabilities | Accrued and other current liabilities consisted of the following: September 30, 2015 December 31, 2014 Interest payable $ 389 $ 382 Customer advances and deposits 105 103 Accrued capital expenditures 821 673 Accrued wages and benefits 200 233 Taxes payable other than income taxes 202 236 Income taxes payable — 54 Deferred income taxes 99 99 Other 284 319 Total accrued and other current liabilities $ 2,100 $ 2,099 |
Reportable Segments (Tables)
Reportable Segments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Sales Revenue, Segment [Member] | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | The following tables present financial information by segment: Three Months Ended Nine Months Ended 2015 2014 2015 2014 Revenues: Intrastate transportation and storage: Revenues from external customers $ 477 $ 557 $ 1,504 $ 2,069 Intersegment revenues 115 44 243 178 592 601 1,747 2,247 Interstate transportation and storage: Revenues from external customers 245 254 755 794 Intersegment revenues 3 4 12 11 248 258 767 805 Midstream: Revenues from external customers 543 1,358 2,067 3,707 Intersegment revenues 840 609 1,715 1,517 1,383 1,967 3,782 5,224 Liquids transportation and services: Revenues from external customers 779 1,148 2,366 2,807 Intersegment revenues 75 48 143 122 854 1,196 2,509 2,929 Investment in Sunoco Logistics: Revenues from external customers 2,379 4,862 8,026 14,080 Intersegment revenues 27 53 155 133 2,406 4,915 8,181 14,213 Retail marketing: Revenues from external customers 1,362 5,985 11,701 16,561 Intersegment revenues 1 3 4 6 1,363 5,988 11,705 16,567 All other: Revenues from external customers 816 769 2,048 2,030 Intersegment revenues 160 128 391 352 976 897 2,439 2,382 Eliminations (1,221 ) (889 ) (2,663 ) (2,319 ) Total revenues $ 6,601 $ 14,933 $ 28,467 $ 42,048 |
Operating Segments [Member] | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Three Months Ended Nine Months Ended 2015 2014 2015 2014 Segment Adjusted EBITDA: Intrastate transportation and storage $ 127 $ 124 $ 421 $ 439 Interstate transportation and storage 286 288 872 905 Midstream 318 379 986 958 Liquids transportation and services 192 163 509 432 Investment in Sunoco Logistics 289 246 836 734 Retail marketing 195 191 464 436 All other 93 60 266 278 Total 1,500 1,451 4,354 4,182 Depreciation, depletion and amortization (471 ) (410 ) (1,451 ) (1,206 ) Interest expense, net of interest capitalized (333 ) (299 ) (979 ) (868 ) Gain on sale of AmeriGas common units — 14 — 177 Losses on interest rate derivatives (64 ) (25 ) (14 ) (73 ) Non-cash unit-based compensation expense (16 ) (18 ) (59 ) (50 ) Unrealized gains (losses) on commodity risk management activities 47 32 (72 ) (1 ) Inventory valuation adjustments (134 ) (51 ) 16 (17 ) Losses on extinguishments of debt (10 ) — (43 ) — Adjusted EBITDA related to discontinued operations — — — (27 ) Adjusted EBITDA related to unconsolidated affiliates (350 ) (184 ) (711 ) (584 ) Equity in earnings of unconsolidated affiliates 214 84 388 265 Other, net 32 (25 ) 51 (49 ) Income from continuing operations before income tax expense $ 415 $ 569 $ 1,480 $ 1,749 |
Assets Segments [Member] | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | September 30, 2015 December 31, 2014 Assets: Intrastate transportation and storage $ 4,889 $ 4,984 Interstate transportation and storage 10,518 10,779 Midstream 16,886 15,562 Liquids transportation and services 7,030 4,568 Investment in Sunoco Logistics 14,586 13,619 Retail marketing 3,173 8,930 All other 7,063 4,232 Total assets $ 64,145 $ 62,674 |
Consolidating Guarantor Finan37
Consolidating Guarantor Financial Information (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Consolidating Balance Sheets [Member] | |
Schedule of Guarantor Obligations [Table Text Block] | September 30, 2015 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash and cash equivalents $ (1 ) $ — $ (14 ) $ 880 $ (7 ) $ 858 All other current assets 4,243 — 541 (317 ) — 4,467 Property, plant, and equipment, net 171 — 9,402 33,328 (80 ) 42,821 Investments in subsidiaries 40,498 — 682 — (41,180 ) — Investments in unconsolidated affiliates 23 — 979 3,865 252 5,119 All other assets 2,335 — 4,529 4,016 — 10,880 Total assets $ 47,269 $ — $ 16,119 $ 41,772 $ (41,015 ) $ 64,145 Current liabilities 395 — 1,113 2,979 (4 ) 4,483 Non-current liabilities 20,889 — 63 11,646 — 32,598 Noncontrolling interest — — — 5,782 208 5,990 Total partners’ capital 25,985 — 14,943 21,365 (41,219 ) 21,074 Total liabilities and equity $ 47,269 $ — $ 16,119 $ 41,772 $ (41,015 ) $ 64,145 December 31, 2014 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash and cash equivalents $ 17 $ — $ — $ 654 $ (8 ) $ 663 All other current assets 273 — 667 4,587 (147 ) 5,380 Property, plant, and equipment, net 103 — 8,948 30,094 (238 ) 38,907 Investments in subsidiaries 24,361 19,829 — 6,755 (50,945 ) — Investments in unconsolidated affiliates 63 — 2,252 2,441 (996 ) 3,760 All other assets 3,826 — 4,765 10,047 (4,674 ) 13,964 Total assets $ 28,643 $ 19,829 $ 16,632 $ 54,578 $ (57,008 ) $ 62,674 Current liabilities 1,117 — 723 5,073 (229 ) 6,684 Non-current liabilities 11,561 5,185 1,575 16,952 (4,594 ) 30,679 Noncontrolling interest — — — 60 5,093 5,153 Predecessor equity — 14,644 14,334 358 (21,248 ) 8,088 Total partners’ capital 15,965 — — 32,135 (36,030 ) 12,070 Total liabilities and equity $ 28,643 $ 19,829 $ 16,632 $ 54,578 $ (57,008 ) $ 62,674 |
Consolidating Statements of Operations [Member] | |
Schedule of Guarantor Obligations [Table Text Block] | Three Months Ended September 30, 2015 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 909 $ 5,682 $ 10 $ 6,601 Operating costs, expenses, and other (6 ) — 894 5,129 8 6,025 Operating income 6 — 15 553 2 576 Interest expense, net (264 ) (23 ) 6 (91 ) 39 (333 ) Equity in earnings of unconsolidated affiliates 504 — 25 128 (443 ) 214 Losses on extinguishments of debt (9 ) (1 ) — — — (10 ) Losses on interest rate derivatives (64 ) — — — — (64 ) Other, net 251 — 1 (182 ) (38 ) 32 Income (loss) before income taxes 424 (24 ) 47 408 (440 ) 415 Income tax expense (benefit) 7 (1 ) — 16 — 22 Income (loss) from continuing operations 417 (23 ) 47 392 (440 ) 393 Net income (loss) 417 (23 ) 47 392 (440 ) 393 Less: Net loss attributable to noncontrolling interest — — — (40 ) 16 (24 ) Net income (loss) attributable to partners $ 417 $ (23 ) $ 47 $ 432 $ (456 ) $ 417 Other comprehensive income $ — $ — $ — $ 84 $ (84 ) $ — Comprehensive income (loss) 417 (23 ) 47 476 (524 ) 393 Comprehensive loss attributable to noncontrolling interest — — — (40 ) 16 (24 ) Comprehensive income (loss) attributable to partners $ 417 $ (23 ) $ 47 $ 516 $ (540 ) $ 417 Three Months Ended September 30, 2014 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 1,467 $ 13,468 $ (2 ) $ 14,933 Operating costs, expenses, and other (17 ) — 1,334 12,810 (4 ) 14,123 Operating income 17 — 133 658 2 810 Interest expense, net (172 ) (85 ) (1 ) (95 ) 54 (299 ) Equity in earnings (losses) of unconsolidated affiliates 474 327 20 (139 ) (598 ) 84 Gain on sale of AmeriGas common units 14 — — — — 14 Losses on interest rate derivatives (25 ) — — — — (25 ) Other, net 42 1 — (5 ) (53 ) (15 ) Income before income taxes 350 243 152 419 (595 ) 569 Income tax expense 10 2 2 41 — 55 Income from continuing operations 340 241 150 378 (595 ) 514 Income from discontinued operations — — 32 — (32 ) — Net income 340 241 182 378 (627 ) 514 Less: Net income attributable to noncontrolling interest — — — 74 4 78 Less: Net loss attributable to predecessor — — — 94 — 94 Net income attributable to partners $ 340 $ 241 $ 182 $ 210 $ (631 ) $ 342 Other comprehensive income (loss) $ 2 $ — $ — $ (16 ) $ 16 $ 2 Comprehensive income 342 241 182 362 (611 ) 516 Comprehensive income attributable to noncontrolling interest — — — 74 4 78 Comprehensive income attributable to predecessor — — — 94 — 94 Comprehensive income attributable to partners $ 342 $ 241 $ 182 $ 194 $ (615 ) $ 344 Nine Months Ended September 30, 2015 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 2,778 $ 25,691 $ (2 ) $ 28,467 Operating costs, expenses, and other (25 ) 1 2,758 23,666 (5 ) 26,395 Operating income (loss) 25 (1 ) 20 2,025 3 2,072 Interest expense, net (622 ) (173 ) 7 (331 ) 140 (979 ) Equity in earnings of unconsolidated affiliates 1,245 106 69 408 (1,440 ) 388 Losses on extinguishments of debt (9 ) (22 ) (12 ) — — (43 ) Losses on interest rate derivatives (14 ) — — — — (14 ) Other, net 731 2 2 (540 ) (139 ) 56 Income (loss) before income taxes 1,356 (88 ) 86 1,562 (1,436 ) 1,480 Income tax expense (benefit) 4 (4 ) — (20 ) — (20 ) Income (loss) from continuing operations 1,352 (84 ) 86 1,582 (1,436 ) 1,500 Income from discontinued operations — — 48 — (48 ) — Net income (loss) 1,352 (84 ) 134 1,582 (1,484 ) 1,500 Less: Net income attributable to noncontrolling interest — — — 170 12 182 Less: Net loss attributable to predecessor — — — (34 ) — (34 ) Net income (loss) attributable to partners $ 1,352 $ (84 ) $ 134 $ 1,446 $ (1,496 ) $ 1,352 Other comprehensive income $ 42 $ — $ — $ 42 $ (42 ) $ 42 Comprehensive income (loss) 1,394 (84 ) 134 1,624 (1,526 ) 1,542 Comprehensive income attributable to noncontrolling interest — — — 170 12 182 Comprehensive loss attributable to predecessor — — — (34 ) — (34 ) Comprehensive income (loss) attributable to partners $ 1,394 $ (84 ) $ 134 $ 1,488 $ (1,538 ) $ 1,394 Nine Months Ended September 30, 2014 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 3,478 $ 38,573 $ (3 ) $ 42,048 Operating costs, expenses, and other (53 ) — 3,306 36,518 (7 ) 39,764 Operating income 53 — 172 2,055 4 2,284 Interest expense, net (521 ) (206 ) (14 ) (276 ) 149 (868 ) Equity in earnings of unconsolidated affiliates 1,459 327 60 181 (1,762 ) 265 Gain on sale of AmeriGas common units 177 — — — — 177 Losses on interest rate derivatives (60 ) — — (13 ) — (73 ) Other, net 124 (7 ) 3 (8 ) (148 ) (36 ) Income before income taxes 1,232 114 221 1,939 (1,757 ) 1,749 Income tax expense 4 3 — 264 — 271 Income from continuing operations 1,228 111 221 1,675 (1,757 ) 1,478 Income from discontinued operations — — 83 66 (83 ) 66 Net income 1,228 111 304 1,741 (1,840 ) 1,544 Less: Net income attributable to noncontrolling interest — — — 208 11 219 Less: Net income attributable to predecessor — — — 97 — 97 Net income attributable to partners $ 1,228 $ 111 $ 304 $ 1,436 $ (1,851 ) $ 1,228 Other comprehensive loss $ (7 ) $ — $ — $ (7 ) $ 7 $ (7 ) Comprehensive income 1,221 111 304 1,734 (1,833 ) 1,537 Comprehensive income attributable to noncontrolling interest — — — 208 11 219 Comprehensive income attributable to predecessor — — — 97 — 97 Comprehensive income attributable to partners $ 1,221 $ 111 $ 304 $ 1,429 $ (1,844 ) $ 1,221 |
Consolidating Statements of Cash Flows [Member] | |
Schedule of Guarantor Obligations [Table Text Block] | Nine Months Ended September 30, 2015 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ (3,435 ) $ (175 ) $ 208 $ 5,593 $ (198 ) $ 1,993 Cash flows from investing activities 999 — (893 ) (5,109 ) (148 ) (5,151 ) Cash flows from financing activities 2,418 175 671 (258 ) 347 3,353 Change in cash (18 ) — (14 ) 226 1 195 Cash at beginning of period 17 — — 654 (8 ) 663 Cash at end of period $ (1 ) $ — $ (14 ) $ 880 $ (7 ) $ 858 Nine Months Ended September 30, 2014 Parent Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ 790 $ (216 ) $ 529 $ 3,063 $ (1,698 ) $ 2,468 Cash flows from investing activities (310 ) (952 ) (564 ) (2,498 ) (211 ) (4,535 ) Cash flows from financing activities (214 ) 1,168 35 (313 ) 1,898 2,574 Change in cash 266 — — 252 (11 ) 507 Cash at beginning of period — — — 568 — 568 Cash at end of period $ 266 $ — $ — $ 820 $ (11 ) $ 1,075 |
Operations And Organization Ope
Operations And Organization Operations And Organization (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||
Jul. 31, 2015 | Apr. 30, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Revenues | $ 6,601 | $ 14,933 | $ 28,467 | $ 42,048 | ||
Net income | 393 | 514 | 1,500 | 1,544 | ||
ETP [Member] | ||||||
Revenues | 6,601 | 13,618 | 27,384 | 38,879 | ||
Net income | 393 | 447 | 1,582 | 1,519 | ||
Regency [Member] | ||||||
Revenues | 0 | 1,483 | 1,300 | 3,524 | ||
Net income | 0 | 107 | (29) | 115 | ||
Adjustments And Eliminations [Member] | ||||||
Revenues | 0 | (168) | (217) | (355) | ||
Net income | 0 | (40) | $ (53) | (90) | ||
Lone Star L.L.C. [Member] | ||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |||||
FEP [Member] | ||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 50.00% | |||||
Citrus [Member] | ||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 50.00% | |||||
Regency [Member] | Lone Star L.L.C. [Member] | ||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 30.00% | |||||
Fayetteville Express Pipeline, LLC [Member] | FEP [Member] | ||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |||||
Citrus [Member] | FGT | ||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |||||
Retail marketing | ||||||
Revenues | 1,363 | 5,988 | $ 11,705 | 16,567 | ||
Excise Taxes Collected | $ 211 | $ 632 | $ 1,710 | $ 1,740 | ||
Sunoco LP Exchange [Member] | ||||||
Stock Repurchased During Period, Shares | 21,000,000 | |||||
IDR Subsidies | $ 35 | |||||
Sunoco LP Exchange [Member] | Sunoco GP [Member] | ||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |||||
Regency Merger [Member] | ||||||
Number of Regency Common Units to be Issued in Acquisition Per Share | 0.4124 | |||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 172,200,000 | |||||
IDR Subsidies | $ 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 | |||||
First year post closing [Member] | Regency Merger [Member] | ||||||
IDR Subsidies | $ 80 | |||||
Four years post closing [Member] | Regency Merger [Member] | ||||||
IDR Subsidies | $ 60 |
Acquisitions, Divestitures an39
Acquisitions, Divestitures and Related Transactions Narrative (Details) $ in Millions, gallons in Billions | 1 Months Ended | 9 Months Ended | 12 Months Ended | ||||||
Oct. 31, 2015USD ($)shares | Jul. 31, 2015USD ($)shares | Apr. 30, 2015USD ($)gallonsshares | Mar. 31, 2015USD ($)shares | Sep. 30, 2015USD ($)shares | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2014USD ($) | |
Business Acquisition [Line Items] | |||||||||
Goodwill | $ 5,633 | $ 7,642 | |||||||
Intangible assets, net | $ 4,494 | $ 5,526 | |||||||
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 | ||||||||
Regency Merger [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Number of Regency Common Units to be Issued in Acquisition Per Share | shares | 0.4124 | ||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 172,200,000 | ||||||||
IDR Subsidies | $ 320 | ||||||||
Dropdown of Sunoco LLC Interest [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage | 31.58% | ||||||||
Gallons of motor fuel distributed | gallons | 5.3 | ||||||||
Business Combination, Consideration Transferred | $ 816 | ||||||||
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 | ||||||||
Bakken Pipeline Transaction [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Payments to Acquire Businesses, Gross | $ 879 | ||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 30,800,000 | ||||||||
Equity Method Investment, Ownership Percentage | 45.00% | ||||||||
Class H Interest in Sunoco Logistics | 90.05% | ||||||||
Sunoco GP [Member] | Sunoco LP Exchange [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||||||
Lone Star L.L.C. [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||||||
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 Susser [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 22,000,000 | ||||||||
Common Units [Member] | Sunoco LP [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Investment Owned, Balance, Shares | shares | 26,800,000 | ||||||||
Subordinated Units [Member] | Sunoco LP [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Investment Owned, Balance, Shares | 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 | ||||||||
Class H Units | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Acquisition Units Acquired | shares | 50,200,000 | ||||||||
Class H Units | Bakken Pipeline Transaction [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Acquisition Units Acquired | shares | 30,800,000 | ||||||||
Class I Units | Bakken Pipeline Transaction [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Acquisition Units Acquired | shares | 100 | ||||||||
First year post closing [Member] | Regency Merger [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
IDR Subsidies | $ 80 | ||||||||
Four years post closing [Member] | Regency Merger [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
IDR Subsidies | $ 60 | ||||||||
ETP [Member] | Sunoco LP [Member] | Dropdown of Susser [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 11,000,000 | ||||||||
Regency [Member] | Lone Star L.L.C. [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 30.00% | ||||||||
Class A Units [Member] | Sunoco LP [Member] | Dropdown of Susser [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 79,308 | ||||||||
Subsequent Event [Member] | Bakken Pipeline Transaction [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Class I Distributions | $ 30 | $ 55 | |||||||
Bakken Pipeline Transaction [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Payments to Acquire Businesses, Gross | $ 382 | ||||||||
Bakken Pipeline Transaction [Member] | Bakken Holdings Company LLC [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 40.00% | ||||||||
Bakken Pipeline Transaction [Member] | Dakota Access and ETCOC [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 75.00% | ||||||||
Bakken Pipeline Transaction [Member] | Class B Units [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 9,400,000 |
Cash And Cash Equivalents Net C
Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Cash and Cash Equivalents [Abstract] | ||
Accounts receivable | $ 523 | $ (782) |
Accounts receivable from related companies | (467) | (40) |
Inventories | (239) | 177 |
Exchanges receivable | 5 | 4 |
Other current assets | (101) | 59 |
Other non-current assets, net | 116 | (23) |
Accounts payable | (988) | 512 |
Accounts payable to related companies | 75 | (10) |
Exchanges payable | (97) | (14) |
Accrued and other current liabilities | 122 | 157 |
Other non-current liabilities | 47 | (52) |
Derivative assets and liabilities, net | 82 | 37 |
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ (922) | $ 25 |
Cash And Cash Equivalents Non-C
Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
NON-CASH INVESTING ACTIVITIES: | ||
Accrued capital expenditures | $ 963 | $ 399 |
Net gains from subsidiary common unit issuances | 118 | 81 |
NON-CASH FINANCING ACTIVITIES: | ||
Capital Contributions from Noncontrolling Interest | 34 | 0 |
Sale of noncontrolling interest in Rover Pipeline LLC to AE-Midco Rover, LLC | 1,946 | 0 |
Noncash or Part Noncash Acquisition, Debt Assumed | 0 | 1,887 |
Long term debt exchanged in connection with acquisition | 0 | 499 |
Predecessor Acquisitions [Member] | ||
NON-CASH FINANCING ACTIVITIES: | ||
Partners' Capital Account, Acquisitions | 0 | 4,281 |
Regency Merger [Member] | ||
NON-CASH FINANCING ACTIVITIES: | ||
Partners' Capital Account, Acquisitions | 9,250 | 0 |
Susser Merger [Member] | ||
NON-CASH FINANCING ACTIVITIES: | ||
Partners' Capital Account, Acquisitions | 0 | 908 |
Bakken Pipeline Transaction [Member] | ||
NON-CASH FINANCING ACTIVITIES: | ||
Redemption of Common Units in connection with Certain Transaction | 999 | 0 |
Sunoco LP Exchange [Member] | ||
NON-CASH FINANCING ACTIVITIES: | ||
Redemption of Common Units in connection with Certain Transaction | 52 | 0 |
Lake Charles LNG Transaction [Member] | ||
NON-CASH FINANCING ACTIVITIES: | ||
Redemption of Common Units in connection with Certain Transaction | $ 0 | $ 1,167 |
Inventories Inventory Schedule
Inventories Inventory Schedule (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Inventory, Gross [Abstract] | ||
Natural gas and NGLs | $ 426 | $ 392 |
Crude oil | 461 | 364 |
Refined products | 95 | 392 |
Other | 241 | 312 |
Total inventories | $ 1,223 | $ 1,460 |
Fair Value Measurements Narrati
Fair Value Measurements Narrative (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2014 | |
Fair Value Measurements [Abstract] | ||
Transfers between levels in fair value hierarchy | $ 0 | |
Aggregate fair value of long-term debt | 26,080 | $ 26,910 |
Long-term Debt | $ 27,450 | $ 25,981 |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Derivative Liability, Fair Value, Gross Liability | $ (445) | $ (771) |
Fair Value, Measurements, Recurring [Member] | ||
Interest rate derivatives, Assets | 22 | 3 |
Price Risk Derivative Assets, at Fair Value | 344 | 745 |
Assets, Fair Value Disclosure, Recurring | 366 | 748 |
Interest rate derivatives, Liabilities | (183) | (155) |
Embedded Derivative, Fair Value of Embedded Derivative Liability | (6) | (16) |
Price Risk Derivative Liabilities, at Fair Value | (256) | (578) |
Liabilities, Fair Value Disclosure, Recurring | (445) | (749) |
Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Interest rate derivatives, Assets | 0 | 0 |
Price Risk Derivative Assets, at Fair Value | 331 | 632 |
Assets, Fair Value Disclosure, Recurring | 331 | 632 |
Interest rate derivatives, Liabilities | 0 | 0 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | (244) | (551) |
Liabilities, Fair Value Disclosure, Recurring | (244) | (551) |
Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Interest rate derivatives, Assets | 22 | 3 |
Price Risk Derivative Assets, at Fair Value | 13 | 113 |
Assets, Fair Value Disclosure, Recurring | 35 | 116 |
Interest rate derivatives, Liabilities | (183) | (155) |
Embedded Derivative, Fair Value of Embedded Derivative Liability | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | (12) | (27) |
Liabilities, Fair Value Disclosure, Recurring | (195) | (182) |
Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Interest rate derivatives, Assets | 0 | 0 |
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Assets, Fair Value Disclosure, Recurring | 0 | 0 |
Interest rate derivatives, Liabilities | 0 | 0 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | (16) | |
Derivative Liability, Fair Value, Gross Liability | (6) | |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Liabilities, Fair Value Disclosure, Recurring | (6) | (16) |
Commodity Derivatives - Condensate [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 36 | |
Commodity Derivatives - Condensate [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Commodity Derivatives - Condensate [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 36 | |
Commodity Derivatives - Condensate [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 5 | 19 |
Price Risk Derivative Liabilities, at Fair Value | (4) | (18) |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 5 | 19 |
Price Risk Derivative Liabilities, at Fair Value | (4) | (18) |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 4 | 26 |
Price Risk Derivative Liabilities, at Fair Value | (5) | (25) |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 4 | 1 |
Price Risk Derivative Liabilities, at Fair Value | (5) | (2) |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 25 |
Price Risk Derivative Liabilities, at Fair Value | 0 | (23) |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 237 | 566 |
Price Risk Derivative Liabilities, at Fair Value | (189) | (490) |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 237 | 541 |
Price Risk Derivative Liabilities, at Fair Value | (189) | (490) |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 25 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | 1 |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 2 | 1 |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 11 | 3 |
Price Risk Derivative Liabilities, at Fair Value | (12) | (4) |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 11 | 3 |
Price Risk Derivative Liabilities, at Fair Value | (12) | (4) |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | 4 |
Price Risk Derivative Liabilities, at Fair Value | (1) | (2) |
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 2 | 4 |
Price Risk Derivative Liabilities, at Fair Value | (1) | (2) |
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 57 | 69 |
Price Risk Derivative Liabilities, at Fair Value | (44) | (32) |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 57 | 46 |
Price Risk Derivative Liabilities, at Fair Value | (44) | (32) |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 23 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 25 | 21 |
Price Risk Derivative Liabilities, at Fair Value | (1) | (7) |
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 25 | 21 |
Price Risk Derivative Liabilities, at Fair Value | (1) | (7) |
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | $ 0 |
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 | ||
Price Risk Derivative Assets, at Fair Value | $ 0 |
Fair Value Measurements Level 3
Fair Value Measurements Level 3 Rollforward (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Derivative, Gain (Loss) on Derivative, Net | $ (12) | $ 22 | $ (14) | $ (77) | |
Fair Value, Measurements, Recurring [Member] | |||||
Liabilities, Fair Value Disclosure, Recurring | (445) | (445) | $ (749) | ||
Fair Value, Measurements, Recurring [Member] | Level 3 | |||||
Liabilities, Fair Value Disclosure, Recurring | (6) | (6) | $ (16) | ||
Other Income (Expenses) [Member] | Embedded Derivatives in Preferred Units [Member] | |||||
Derivative, Gain (Loss) on Derivative, Net | $ 6 | $ (1) | $ 10 | $ (11) |
Net Income Per Limited Partne46
Net Income Per Limited Partner Unit Reconciliation of Net Income and Weighted Avg Units Used in Computing Basic and Diluted EPU (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Earnings Per Share [Abstract] | ||||
Income from continuing operations | $ 393 | $ 514 | $ 1,500 | $ 1,478 |
Less: Income (loss) from continuing operations attributable to noncontrolling interest | (24) | 78 | 182 | 219 |
Less: Net loss attributable to predecessor | 0 | 94 | (34) | 97 |
Income from continuing operations, net of noncontrolling interest and predecessor income | 417 | 342 | 1,352 | 1,162 |
General Partner’s interest in income from continuing operations | 277 | 135 | 779 | 373 |
Class H Unitholder’s interest in income from continuing operations | 66 | 59 | 184 | 159 |
Class I Unitholder's Interest in Net Income | 15 | 0 | 80 | 0 |
Common Unitholders’ interest in income from continuing operations | 59 | 148 | 309 | 630 |
Additional earnings allocated to General Partner | (3) | 0 | (7) | (2) |
Distributions on employee unit awards, net of allocation to General Partner | (4) | (3) | (11) | (9) |
Income from continuing operations available to Common Unitholders | 52 | 145 | 291 | 619 |
Income attributable to Preferred Units | (4) | 0 | (5) | 0 |
Net Income (Loss) Available to Common Stockholders, Diluted | $ 48 | $ 145 | $ 286 | $ 619 |
Weighted average Common Units – basic | 485 | 331.4 | 415.1 | 324.8 |
Basic income from continuing operations per Common Unit | $ 0.11 | $ 0.44 | $ 0.70 | $ 1.91 |
Dilutive effect of unvested employee unit awards | 1.4 | 1.7 | 1.7 | 1.6 |
Dilutive effect of Preferred Units | 0.9 | 0 | 0.9 | 0 |
Weighted average Common Units - diluted | 487.3 | 333.1 | 417.7 | 326.4 |
Diluted income from continuing operations per Common Unit | $ 0.10 | $ 0.44 | $ 0.68 | $ 1.90 |
Basic income from discontinued operations per Common Unit | 0 | 0 | 0 | 0.20 |
Diluted income from discontinued operations per Common Unit | $ 0 | $ 0 | $ 0 | $ 0.20 |
Debt Obligations Debt Table (De
Debt Obligations Debt Table (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Aug. 30, 2015 | Apr. 30, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||||
Other Long-term Debt | $ 31 | $ 223 | |||
Debt Instrument, Unamortized Discount (Premium), Net | 172 | 280 | |||
Long-term Debt | 27,450 | 25,981 | |||
Current maturities of long-term debt | 1 | 1,008 | |||
Long-term debt, less current maturities | 27,449 | 24,973 | |||
ETP [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 19,440 | 10,890 | |||
ETP [Member] | ETP Revolving Credit Facility, due November 2019 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Line of Credit | 665 | 570 | |||
Transwestern [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 782 | 782 | |||
Panhandle [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 1,085 | 1,085 | |||
Sunoco, Inc. [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 465 | 715 | |||
Sunoco Logistics [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | [1] | 3,975 | 3,975 | ||
Sunoco Logistics [Member] | Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Line of Credit | [2] | 0 | $ 35 | 35 | |
Sunoco Logistics [Member] | Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Line of Credit | 835 | 150 | |||
Sunoco LP [Member] | Sunoco LP Revolving Credit Facility Due September 2019 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Line of Credit | [3] | 0 | 683 | ||
Regency [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | [4] | 0 | $ 5,100 | 5,089 | |
Regency [Member] | 5.75% Senior Notes due September 1, 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | $ 400 | ||||
Regency [Member] | 6.5% Senior Notes, due July 15, 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 500 | ||||
Regency [Member] | 5.875% Senior Notes due March 1, 2022 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 900 | ||||
Regency [Member] | 5.5% Senior Notes, due April 15, 2023 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 700 | ||||
Regency [Member] | Regency 4.50% Senior Notes Due 2023 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 600 | ||||
Regency [Member] | 8.375% Senior Notes due June 1, 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 390 | ||||
Regency [Member] | 6.5% Senior Notes due May 15, 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 260 | ||||
Regency [Member] | 5.0% Senior Notes due October 1, 2022 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | $ 700 | ||||
Regency [Member] | Regency Revolving Credit Facility due May 21, 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Line of Credit | [5] | $ 0 | $ 1,504 | ||
[1] | (1) Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of September 30, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. | ||||
[2] | (3) Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility matured in April 2015 and was repaid with borrowings from the Sunoco Logistics $2.5 billion Revolving Credit Facility. | ||||
[3] | (5) In connection with ETE’s acquisition of Sunoco GP, the general partner of Sunoco LP, on July 1, 2015, ETP deconsolidated Sunoco LP. | ||||
[4] | (2) As discussed below, the Regency senior notes were redeemed and/or assumed by the Partnership. | ||||
[5] | (4) On April 30, 2015, in connection with the Regency Merger, the Regency Credit Facility was paid off in full and terminated. |
Debt Obligations Future Maturit
Debt Obligations Future Maturities Table (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Long-term Debt | $ 27,450 | $ 25,981 |
Excluding unamortized premiums and fair value adjustments [Member] | ||
2015 (remainder) | 1 | |
2,016 | 375 | |
2,017 | 1,182 | |
2,018 | 2,485 | |
2,019 | 1,666 | |
Thereafter | 21,569 | |
Long-term Debt | $ 27,278 |
Debt Obligations Narrative (Det
Debt Obligations Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||
Aug. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Apr. 30, 2015 | Dec. 31, 2014 | ||
Debt Instrument, Unamortized Discount (Premium), Net | $ 172 | $ 280 | ||||||
Proceeds from Issuance of Long-term Debt | $ 14,808 | $ 9,224 | ||||||
Regency 4.50% Senior Notes Due 2023 [Member] | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.50% | |||||||
ETP [Member] | ||||||||
Senior notes, aggregate principal amount | $ 19,440 | 10,890 | ||||||
Proceeds from Issuance of Long-term Debt | $ 2,980 | $ 2,480 | ||||||
ETP [Member] | 2.50% Senior Notes due June 2018 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 650 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.50% | |||||||
ETP [Member] | 4.15% Senior Notes due October 1, 2020 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 350 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.15% | |||||||
ETP [Member] | 4.75% Senior Notes due January 2026 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 1,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | |||||||
ETP [Member] | 6.125% Senior Notes due December 2045 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 1,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.125% | |||||||
ETP [Member] | 4.05% Senior Notes due March 2025 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 1,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.05% | |||||||
ETP [Member] | ETP Revolving Credit Facility, due November 2019 [Member] | ||||||||
Line of Credit Facility, Current Borrowing Capacity | 3,750 | |||||||
Long-term Line of Credit | 665 | 570 | ||||||
ETP [Member] | 4.90% Senior Notes due March 2035 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 500 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.90% | |||||||
ETP [Member] | 5.15% Senior Notes due March 2045 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 1,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.15% | |||||||
Sunoco Logistics [Member] | ||||||||
Senior notes, aggregate principal amount | [1] | 3,975 | 3,975 | |||||
Sunoco Logistics [Member] | 6.125% Senior Notes, due May 15, 2016 [Member] | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.125% | |||||||
Sunoco Logistics [Member] | Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member] | ||||||||
Long-term Line of Credit | [2] | 0 | $ 35 | 35 | ||||
Sunoco Logistics [Member] | Sunoco Logistics Revolving Credit Facility, due March 2020 [Member] | ||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 1,500 | |||||||
Sunoco Logistics [Member] | Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member] | ||||||||
Line of Credit Facility, Current Borrowing Capacity | 2,500 | |||||||
Long-term Line of Credit | 835 | 150 | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | 3,250 | |||||||
Regency [Member] | ||||||||
Senior notes, aggregate principal amount | [3] | $ 0 | $ 5,100 | $ 5,089 | ||||
Regency [Member] | 5.75% Senior Notes due September 1, 2020 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 400 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.75% | |||||||
Regency [Member] | 8.375% Senior Notes due June 1, 2019 [Member] | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.375% | |||||||
Early Repayment of Senior Debt | $ 499 | |||||||
Regency [Member] | 8.375% Senior Notes due June 1, 2020 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 390 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.375% | |||||||
Redemption Premium | $ 40 | |||||||
Regency [Member] | 6.5% Senior Notes due May 15, 2021 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 260 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | |||||||
Redemption Premium | $ 24 | |||||||
Regency [Member] | 4.5% Senior Notes due November 1, 2023 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 600 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.50% | |||||||
Regency [Member] | 6.5% Senior Notes, due July 15, 2021 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 500 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | |||||||
Regency [Member] | 5.0% Senior Notes due October 1, 2022 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 700 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.00% | |||||||
Regency [Member] | 5.875% Senior Notes due March 1, 2022 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 900 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.875% | |||||||
Regency [Member] | Regency 4.50% Senior Notes Due 2023 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 600 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.50% | |||||||
Regency [Member] | 5.5% Senior Notes, due April 15, 2023 [Member] | ||||||||
Senior notes, aggregate principal amount | $ 700 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | |||||||
[1] | (1) Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of September 30, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. | |||||||
[2] | (3) Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility matured in April 2015 and was repaid with borrowings from the Sunoco Logistics $2.5 billion Revolving Credit Facility. | |||||||
[3] | (2) As discussed below, the Regency senior notes were redeemed and/or assumed by the Partnership. |
Series A Preferred Units (Detai
Series A Preferred Units (Details) shares in Millions | 9 Months Ended | |
Sep. 30, 2015shares | Apr. 30, 2015USD ($)$ / commonunitshares | |
Preferred Units 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 | |
Preferred Units Redemption Amount | $ 35,000,000 | |
Regency Merger [Member] | ||
Preferred Units, Issued | shares | 1.9 |
Equity Narrative (Details)
Equity Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Jul. 31, 2015 | Apr. 30, 2015 | Mar. 31, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | |
Subsidiary units issued for cash | $ 118 | ||||||
Net gains from subsidiary common unit issuances | 118 | $ 81 | |||||
Proceeds from Issuance of Common Limited Partners Units | 1,030 | $ 1,126 | |||||
Sunoco Logistics [Member] | |||||||
Proceeds from Issuance of Common Stock | $ 82 | $ 547 | |||||
Partners' Capital Account, Units, Sale of Units | 13,500,000 | ||||||
Stock Issued During Period, Shares, New Issues | 2,000,000 | ||||||
ETP [Member] | |||||||
Equity Distribution Agreements, Value of Units Available to be Issued | $ 624 | ||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 255 | ||||||
Common units issued in connection with the Distribution Reinvestment Plan | 5,000,000 | ||||||
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan | 2,300,000 | ||||||
Equity Distribution Agreement [Member] | Sunoco Logistics [Member] | |||||||
Fees and Commissions | $ 7 | ||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units | 1,250 | ||||||
Proceeds from Issuance of Common Limited Partners Units | 645 | ||||||
Equity Distribution Agreement [Member] | ETP [Member] | |||||||
Proceeds from Issuance of Common Stock | 775 | ||||||
Fees and Commissions | $ 8 | ||||||
Bakken Pipeline Transaction [Member] | |||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 30,800,000 | ||||||
Equity Method Investment, Ownership Percentage | 45.00% | ||||||
Payments to Acquire Businesses, Gross | $ 879 | ||||||
Class H Interest in Sunoco Logistics | 90.05% | ||||||
Bakken Pipeline Transaction [Member] | Subsequent Event [Member] | |||||||
Class I Distributions | $ 30 | $ 55 | |||||
Sunoco LP Exchange [Member] | |||||||
Stock Repurchased During Period, Shares | 21,000,000 | ||||||
IDR Subsidies | $ 35 | ||||||
Term of IDR Subsidy | 10 years | ||||||
Sunoco LP Exchange [Member] | Sunoco GP [Member] | |||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||||
Class H Units | |||||||
Business Acquisition Units Acquired | 50,200,000 | ||||||
Class H Units | Bakken Pipeline Transaction [Member] | |||||||
Business Acquisition Units Acquired | 30,800,000 | ||||||
Class I Units | Bakken Pipeline Transaction [Member] | |||||||
Business Acquisition Units Acquired | 100 | ||||||
Sunoco Logistics Revolving Credit Facility, due March 2020 [Member] | Sunoco Logistics [Member] | |||||||
Line of Credit Facility, Current Borrowing Capacity | $ 1,500 |
Equity Common Unit Activity (De
Equity Common Unit Activity (Details) shares in Millions | 9 Months Ended |
Sep. 30, 2015shares | |
Number of common units at December 31, 2014 | 355.5 |
Number of common units at September 30, 2015 | 495.6 |
Partners' Capital Account, Units, Unit-based Compensation | 0.2 |
ETP [Member] | |
Common units issued in connection with Equity Distribution Agreements | 14.5 |
Common units issued in connection with the Distribution Reinvestment Plan | 5 |
ETP [Member] | Regency Merger [Member] | |
Stock Issued During Period, Shares, New Issues | 172.2 |
ETP [Member] | Bakken Pipeline Transaction [Member] | |
Stock Redeemed or Called During Period, Shares | (30.8) |
ETP [Member] | Sunoco LP Exchange [Member] | |
Stock Redeemed or Called During Period, Shares | (21) |
Equity Quarterly Distributions
Equity Quarterly Distributions Of Available Cash (Details) - $ / shares | 3 Months Ended | |||
Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | |
ETP [Member] | ||||
Distribution Made to Member or Limited Partner [Line Items] | ||||
Record Date | Nov. 5, 2015 | Aug. 6, 2015 | May 8, 2015 | Feb. 6, 2015 |
Payment Date | Nov. 16, 2015 | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 |
Rate | $ 1.0550 | $ 1.0350 | $ 1.0150 | $ 0.9950 |
Sunoco Logistics [Member] | ||||
Distribution Made to Member or Limited Partner [Line Items] | ||||
Record Date | Nov. 9, 2015 | Aug. 10, 2015 | May 11, 2015 | Feb. 9, 2015 |
Payment Date | Nov. 13, 2015 | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 |
Rate | $ 0.4580 | $ 0.4380 | $ 0.4190 | $ 0.4000 |
Equity Net IDR Schedule (Detail
Equity Net IDR Schedule (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Subsequent Event [Member] | |||||
Relinquishment of Incentive Distributions | $ 28 | $ 95 | $ 105 | $ 128 | $ 137 |
Equity Accumulated Other Compre
Equity Accumulated Other Comprehensive Income, Net Of Tax (Details) - USD ($) $ in Millions | 9 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | |
Partners' Capital Notes [Abstract] | ||
Available-for-sale securities | $ 2 | $ 3 |
Foreign currency translation adjustment | (4) | (3) |
Net loss on commodity related hedges | 0 | (1) |
Actuarial loss related to pensions and other postretirement benefits | (12) | (57) |
Investments in unconsolidated affiliates, net | 0 | 2 |
Total AOCI, net of tax | $ (14) | $ (56) |
Income Taxes Narrative (Details
Income Taxes Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Jul. 31, 2015 | |
Investments, Owned, Federal Income Tax Note [Line Items] | |||||
Income Tax Expense (Benefit) | $ 22 | $ 55 | $ (20) | $ 271 | |
Benefit attributable to statutory rate change [Member] | |||||
Investments, Owned, Federal Income Tax Note [Line Items] | |||||
Income Tax Expense (Benefit) | 24 | ||||
Unfavorable [Member] | |||||
Investments, Owned, Federal Income Tax Note [Line Items] | |||||
Tax Adjustments, Settlements, and Unusual Provisions | $ 87 | ||||
Reduction in franchise tax [Member] | |||||
Investments, Owned, Federal Income Tax Note [Line Items] | |||||
Income Tax Expense (Benefit) | $ 11 | ||||
Tax Years 2004 - 2009 [Member] | Southern Union [Member] | |||||
Investments, Owned, Federal Income Tax Note [Line Items] | |||||
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | $ 7 |
Regulatory Matters, Commitmen57
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details) | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||
Sep. 30, 2013USD ($) | Nov. 30, 2012USD ($) | Jan. 31, 2012USD ($) | Sep. 30, 2015USD ($)sites | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)sites | Sep. 30, 2014USD ($) | Dec. 31, 2014USD ($) | |
Maximum lease expiration year | Dec. 31, 2058 | |||||||
Operating Leases, Rent Expense, Contingent Rentals | $ 9,000,000 | $ 8,000,000 | $ 19,000,000 | $ 17,000,000 | ||||
Loss contingency accrual, at carrying value | 38,000,000 | 38,000,000 | $ 37,000,000 | |||||
Amounts recorded in balance sheets for contingencies and current litigation not disclosed | $ 0 | 0 | ||||||
Environmental Costs Recognized, Recovery Credited to Expense | $ 19,000,000 | |||||||
Sites where remediation operations are responsibility of third parties | sites | 19 | 19 | ||||||
Regency 4.50% Senior Notes Due 2023 [Member] | ||||||||
Guarantor Obligations, Current Carrying Value | $ 600,000,000 | $ 600,000,000 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.50% | 4.50% | ||||||
Disgorgement [Member] | ||||||||
Gain Contingency, Unrecorded Amount | $ 595,000,000 | $ 595,000,000 | ||||||
Compensatory Damages [Member] | ||||||||
Gain Contingency, Unrecorded Amount | 319,000,000 | 319,000,000 | ||||||
Expense Reimbursement [Member] | ||||||||
Gain Contingency, Unrecorded Amount | 1,000,000 | 1,000,000 | ||||||
Final Judgement [Member] | ||||||||
Gain Contingency, Unrecorded Amount | $ 536,000,000 | $ 536,000,000 | ||||||
FGT | ||||||||
Proceeds from Legal Settlements | $ 100,000,000 | |||||||
FGT | I-595 Project [Member] | ||||||||
Loss Contingency, Damages Awarded, Value | $ 19,000,000 | |||||||
FGT | Turnpike/State Road 91 [Member] | ||||||||
Loss Contingency, Damages Awarded, Value | $ 1,000,000 | |||||||
AmeriGas [Member] | ||||||||
Contingent Residual Support Agreement, Amount | $ 1,550,000,000 | |||||||
Sunoco, Inc. [Member] | ||||||||
Loss Contingency, Pending Claims, Number | 6 | 6 | ||||||
Sunoco, Inc. [Member] | Multidistrict Legislation [Member] | ||||||||
Loss Contingency, Pending Claims, Number | 4 | 4 | ||||||
Southern Union [Member] | ||||||||
Loss Contingency, Estimated Recovery from Third Party | 150,000 | |||||||
Percentage Of Recovery | 50.00% | |||||||
Sunoco [Member] | ||||||||
Sites where remediation operations are responsibility of third parties | 52 | 52 | ||||||
Payments for Environmental Liabilities | $ 9,000,000 | $ 10,000,000 | $ 27,000,000 | $ 27,000,000 |
Regulatory Matters, Commitmen58
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Operating Leases, Rental Expense (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Rental expense(1) | [1] | $ 35 | $ 31 | $ 141 | $ 90 |
Less: Sublease rental income | (3) | (9) | (15) | (27) | |
Rental expense, net | $ 32 | $ 22 | $ 126 | $ 63 | |
[1] | (1) Includes contingent rentals totaling $9 million and $8 million for the three months ended September 30, 2015 and 2014 and $19 million and $17 million for the nine months ended September 30, 2015 and 2014, respectively. |
Regulatory Matters, Commitmen59
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Environmental Exit Cost [Line Items] | ||
Current | $ 48 | $ 41 |
Non-current | 327 | 360 |
Total environmental liabilities | $ 375 | $ 401 |
Derivative Assets And Liabili60
Derivative Assets And Liabilities Narrative (Details) $ in Millions | 1 Months Ended |
Apr. 30, 2015USD ($) | |
Regency [Member] | |
Proceeds From Termination of Commodity Swaps | $ 56 |
Derivative Assets And Liabili61
Derivative Assets And Liabilities Outstanding Commodity-Related Derivatives (Details) | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2015MMbtubarrelsMegawattbbl | Dec. 31, 2014MMbtubarrelsMegawattbbl | ||
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member] | |||
Notional Volume | MMbtu | (37,555,000) | (39,287,500) | |
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | MMbtu | (232,500) | ||
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | |||
Notional Volume | MMbtu | (2,750,700) | ||
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member] | |||
Notional Volume | MMbtu | (37,555,000) | (39,287,500) | |
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | MMbtu | [1] | (13,907,500) | |
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | |||
Notional Volume | MMbtu | [1] | (32,677,500) | |
Natural Gas [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Notional Volume | MMbtu | 0 | ||
Term Of Commodity Derivatives | 2,015 | ||
Natural Gas [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | |||
Notional Volume | MMbtu | (5,000,000) | ||
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | 2,015 | |
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Long [Member] | |||
Notional Volume | MMbtu | (37,555,000) | (39,287,500) | |
Natural Gas [Member] | Minimum [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | 2,015 | |
Natural Gas [Member] | Minimum [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Natural Gas [Member] | Minimum [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Natural Gas [Member] | Minimum [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | 2,015 | |
Natural Gas [Member] | Minimum [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Natural Gas [Member] | Maximum [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | 2,016 | |
Natural Gas [Member] | Maximum [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Natural Gas [Member] | Maximum [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Natural Gas [Member] | Maximum [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | 2,016 | |
Natural Gas [Member] | Maximum [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Natural Gas Liquids and Crude [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | bbl | (6,138,800) | (4,417,400) | |
Natural Gas Liquids and Crude [Member] | Minimum [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | 2,015 | |
Natural Gas Liquids and Crude [Member] | Maximum [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | 2,016 | |
Power [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | (17,292,500) | (34,304,000) | |
Power [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | 2,015 | |
Power [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | (1,537,218) | (9,116,777) | |
Power [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Notional Volume | (57,500) | ||
Term Of Commodity Derivatives | 2,015 | ||
Power [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | (6,872,500) | ||
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | 2,015 | |
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | (11,361) | (72,000) | |
Power [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | 2,015 | |
Power [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | (55,618) | ||
Power [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | |||
Notional Volume | (198,556) | ||
Power [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Power [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | |||
Notional Volume | (557,220) | (288,775) | |
Power [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Power [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | |||
Notional Volume | (73,757,500) | (46,150,000) | |
Power [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Power [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | (846,164) | (156,000) | |
Power [Member] | Minimum [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Power [Member] | Minimum [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Power [Member] | Maximum [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Power [Member] | Maximum [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
Crude Oil [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Notional Volume | 0 | ||
Term Of Commodity Derivatives | 2,015 | ||
Crude Oil [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | (140,000) | ||
Refined Products [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Refined Products [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member] | |||
Notional Volume | barrels | (2,273,000) | ||
Refined Products [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member] | |||
Notional Volume | barrels | (13,745,755) | ||
Refined Products [Member] | Minimum [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,015 | ||
Refined Products [Member] | Maximum [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | |||
Term Of Commodity Derivatives | 2,016 | ||
[1] | (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 Liabili62
Derivative Assets And Liabilities Interest Rate Swaps Outstanding (Details) - Interest rate derivatives - ETP [Member] - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2015 | Dec. 31, 2014 | ||
July 2015 [Member] | |||
Notional Amount | [1] | $ 0 | $ 200 |
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.40% and receive a floating rate | |
July 2016 [Member] | |||
Notional Amount | [3] | $ 200 | 200 |
Type | [2],[3] | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | |
July 2017 [Member] | |||
Notional Amount | [4] | $ 300 | 300 |
Type | [2],[4] | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | |
July 2018 [Member] | |||
Notional Amount | [4] | $ 200 | 200 |
Type | [2],[4] | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | |
July 2019 [Member] | |||
Notional Amount | [4] | $ 200 | 300 |
Type | [2],[4] | Forward-starting to pay a fixed rate of 3.25% and receive a floating rate | |
December 2018 [Member] | |||
Notional Amount | $ 1,200 | 0 | |
Type | [2] | Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53% | |
March 2019 [Member] | |||
Notional Amount | $ 300 | 0 | |
Type | [2] | Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.42% | |
February 2023 [Member] | |||
Notional Amount | $ 0 | $ 200 | |
Type | [2] | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | |
[1] | Represents the effective date. These forward-starting swaps have terms of 10 years with a mandatory termination date the same as the effective date. | ||
[2] | Floating rates are based on 3-month LIBOR. | ||
[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. |
Derivative Assets And Liabili63
Derivative Assets And Liabilities Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Total derivatives assets | $ 366 | $ 770 |
Total derivatives liabilities | (445) | (771) |
Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 18 | 43 |
Total derivatives liabilities | (1) | 0 |
Not Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 348 | 727 |
Total derivatives liabilities | (444) | (771) |
Embedded Derivatives in Preferred Units [Member] | Not Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 0 | 0 |
Total derivatives liabilities | (6) | (16) |
Commodity derivatives (margin deposits) | Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 18 | 43 |
Total derivatives liabilities | (1) | 0 |
Commodity derivatives (margin deposits) | Not Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 313 | 617 |
Total derivatives liabilities | (243) | (577) |
Commodity derivatives | Not Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 13 | 107 |
Total derivatives liabilities | (12) | (23) |
Interest rate derivatives | Not Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 22 | 3 |
Total derivatives liabilities | $ (183) | $ (155) |
Derivative Assets And Liabili64
Derivative Assets And Liabilities Fair Value of Derivatives, Netting Basis (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 366 | $ 770 |
Derivative Liability, Fair Value, Gross Liability | (445) | (771) |
Derivative Asset, Fair Value, Amount Offset Against Collateral | (10) | (19) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 10 | 19 |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (244) | (577) |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 244 | 577 |
Derivative Asset, Fair Value, Net | 112 | 174 |
Derivative Liability, Fair Value, Net | (191) | (175) |
Without offsetting agreements [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 22 | 3 |
Derivative Liability, Fair Value, Gross Liability | (189) | (171) |
OTC Contracts [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 13 | 107 |
Derivative Liability, Fair Value, Gross Liability | (12) | (23) |
Broker cleared derivative contracts [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 331 | 660 |
Derivative Liability, Fair Value, Gross Liability | $ (244) | $ (577) |
Derivative Assets And Liabili65
Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Recognized OCI On Derivatives (Effective Portion) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Change in Value Recognized in OCI on Derivatives (Effective Portion) | $ 0 | $ 3 | $ 1 | $ (3) |
Derivatives In Cash Flow Hedging Relationships - Commodity Derivatives [Member] | ||||
Change in Value Recognized in OCI on Derivatives (Effective Portion) | $ 0 | $ 3 | $ 1 | $ (3) |
Derivative Assets And Liabili66
Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Amount Of Gain/(Loss) Reclassified From AOCI Into Income (Effective Portion) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | $ 0 | $ 0 | $ 0 | $ (6) |
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness | (1) | 1 | 7 | (5) |
Derivative, Gain (Loss) on Derivative, Net | (12) | 22 | (14) | (77) |
Losses on interest rate derivatives | (64) | (25) | (14) | (73) |
Commodity Derivatives - Trading [Member] | ||||
Derivative, Gain (Loss) on Derivative, Net | (2) | (4) | (10) | (2) |
Commodity derivatives | ||||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | 0 | 0 | 0 | (6) |
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness | (1) | 1 | 7 | (5) |
Derivative, Gain (Loss) on Derivative, Net | 48 | 52 | 0 | 9 |
Other Income (Expenses) [Member] | Embedded Derivatives in Preferred Units [Member] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 6 | $ (1) | $ 10 | $ (11) |
Related Party Transactions Narr
Related Party Transactions Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | |
Lake Charles LNG | |||
Management Fees Revenue | $ 75 | ||
Motor Fuels [Member] | Sunoco LP [Member] | |||
Affiliate Costs | $ 500 | ||
Subsequent Event [Member] | Lake Charles LNG | |||
Management Fees Revenue | $ 75 |
Related Party Transactions Affi
Related Party Transactions Affiliated Revenue (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Related Party Transactions [Abstract] | ||||
Affiliated revenues | $ 94 | $ 262 | $ 300 | $ 951 |
Related Party Transactions Rela
Related Party Transactions Related Party A/R and A/P (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Total accounts receivable from related companies: | $ 428 | $ 139 |
Total accounts payable to related companies: | 256 | 25 |
ETE | ||
Total accounts receivable from related companies: | 135 | 11 |
Sunoco LP [Member] | ||
Total accounts payable to related companies: | 230 | 0 |
PES | ||
Total accounts receivable from related companies: | 12 | 6 |
Total accounts payable to related companies: | 5 | 0 |
FGT | ||
Total accounts receivable from related companies: | 77 | 9 |
Total accounts payable to related companies: | 0 | 2 |
Lake Charles LNG | ||
Total accounts receivable from related companies: | 4 | 3 |
Total accounts payable to related companies: | 3 | 2 |
Trans-Pecos Pipeline, LLC [Member] | ||
Total accounts receivable from related companies: | 50 | 0 |
Total accounts payable to related companies: | 4 | 0 |
Comanche Trail Pipeline, LLC [Member] | ||
Total accounts receivable from related companies: | 72 | 0 |
Other | ||
Total accounts receivable from related companies: | 78 | 110 |
Total accounts payable to related companies: | $ 14 | $ 21 |
Other Information Other Current
Other Information Other Current Assets (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Other Information [Abstract] | ||
Deposits paid to vendors | $ 99 | $ 65 |
Deferred Tax Assets, Net, Current | 0 | 14 |
Income Taxes Receivable, Current | 99 | 17 |
Prepaid expenses and other | 157 | 200 |
Total other current assets | $ 355 | $ 296 |
Other Information Accrued and O
Other Information Accrued and Other Current Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Other Information [Abstract] | ||
Interest payable | $ 389 | $ 382 |
Customer advances and deposits | 105 | 103 |
Accrued Capital Expenditures | 821 | 673 |
Accrued wages and benefits | 200 | 233 |
Taxes payable other than income taxes | 202 | 236 |
Income taxes payable | 0 | 54 |
Deferred income taxes | 99 | 99 |
Other | 284 | 319 |
Total accrued and other current liabilities | $ 2,100 | $ 2,099 |
Reportable Segments Segment Rev
Reportable Segments Segment Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Segment Reporting Information [Line Items] | ||||
Revenues | $ 6,601 | $ 14,933 | $ 28,467 | $ 42,048 |
Intrastate transportation and storage | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 592 | 601 | 1,747 | 2,247 |
Intrastate transportation and storage | Revenues from external customers | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 477 | 557 | 1,504 | 2,069 |
Intrastate transportation and storage | Intersegment revenues | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 115 | 44 | 243 | 178 |
Interstate transportation and storage | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 248 | 258 | 767 | 805 |
Interstate transportation and storage | Revenues from external customers | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 245 | 254 | 755 | 794 |
Interstate transportation and storage | Intersegment revenues | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 3 | 4 | 12 | 11 |
Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 1,383 | 1,967 | 3,782 | 5,224 |
Midstream | Revenues from external customers | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 543 | 1,358 | 2,067 | 3,707 |
Midstream | Intersegment revenues | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 840 | 609 | 1,715 | 1,517 |
Liquids transportation and services | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 854 | 1,196 | 2,509 | 2,929 |
Liquids transportation and services | Revenues from external customers | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 779 | 1,148 | 2,366 | 2,807 |
Liquids transportation and services | Intersegment revenues | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 75 | 48 | 143 | 122 |
Investment in Sunoco Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 2,406 | 4,915 | 8,181 | 14,213 |
Investment in Sunoco Logistics | Revenues from external customers | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 2,379 | 4,862 | 8,026 | 14,080 |
Investment in Sunoco Logistics | Intersegment revenues | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 27 | 53 | 155 | 133 |
Retail marketing | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 1,363 | 5,988 | 11,705 | 16,567 |
Retail marketing | Revenues from external customers | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 1,362 | 5,985 | 11,701 | 16,561 |
Retail marketing | Intersegment revenues | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 1 | 3 | 4 | 6 |
All other | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 976 | 897 | 2,439 | 2,382 |
All other | Revenues from external customers | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 816 | 769 | 2,048 | 2,030 |
All other | Intersegment revenues | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 160 | 128 | 391 | 352 |
Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | $ (1,221) | $ (889) | $ (2,663) | $ (2,319) |
Reportable Segments Segment Adj
Reportable Segments Segment Adjusted EBITDA (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Segment Reporting Information [Line Items] | ||||
Segment Adjusted EBITDA | $ 1,500 | $ 1,451 | $ 4,354 | $ 4,182 |
Depreciation, depletion and amortization | (471) | (410) | (1,451) | (1,206) |
Interest expense, net of interest capitalized | (333) | (299) | (979) | (868) |
Gain on sale of AmeriGas common units | 0 | 14 | 0 | 177 |
Losses on interest rate derivatives | (64) | (25) | (14) | (73) |
Non-cash unit-based compensation expense | (16) | (18) | (59) | (50) |
Unrealized gains (losses) on commodity risk management activities | 47 | 32 | (72) | (1) |
Inventory valuation adjustments | (134) | (51) | 16 | (17) |
Losses on Extinguishments of Debt | (10) | 0 | (43) | 0 |
Adjusted EBITDA related to discontinued operations | 0 | 0 | 0 | (27) |
Adjusted EBITDA related to unconsolidated affiliates | (350) | (184) | (711) | (584) |
Equity in earnings of unconsolidated affiliates | 214 | 84 | 388 | 265 |
Other, net | 32 | (25) | 51 | (49) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 415 | 569 | 1,480 | 1,749 |
Intrastate transportation and storage | ||||
Segment Reporting Information [Line Items] | ||||
Segment Adjusted EBITDA | 127 | 124 | 421 | 439 |
Interstate transportation and storage | ||||
Segment Reporting Information [Line Items] | ||||
Segment Adjusted EBITDA | 286 | 288 | 872 | 905 |
Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Segment Adjusted EBITDA | 318 | 379 | 986 | 958 |
Liquids transportation and services | ||||
Segment Reporting Information [Line Items] | ||||
Segment Adjusted EBITDA | 192 | 163 | 509 | 432 |
Investment in Sunoco Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Segment Adjusted EBITDA | 289 | 246 | 836 | 734 |
Retail marketing | ||||
Segment Reporting Information [Line Items] | ||||
Segment Adjusted EBITDA | 195 | 191 | 464 | 436 |
All other | ||||
Segment Reporting Information [Line Items] | ||||
Segment Adjusted EBITDA | $ 93 | $ 60 | $ 266 | $ 278 |
Reportable Segments Segment Ass
Reportable Segments Segment Assets (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Assets | $ 64,145 | $ 62,674 |
Intrastate transportation and storage | ||
Segment Reporting Information [Line Items] | ||
Assets | 4,889 | 4,984 |
Interstate transportation and storage | ||
Segment Reporting Information [Line Items] | ||
Assets | 10,518 | 10,779 |
Midstream | ||
Segment Reporting Information [Line Items] | ||
Assets | 16,886 | 15,562 |
Liquids transportation and services | ||
Segment Reporting Information [Line Items] | ||
Assets | 7,030 | 4,568 |
Investment in Sunoco Logistics | ||
Segment Reporting Information [Line Items] | ||
Assets | 14,586 | 13,619 |
Retail marketing | ||
Segment Reporting Information [Line Items] | ||
Assets | 3,173 | 8,930 |
All other | ||
Segment Reporting Information [Line Items] | ||
Assets | $ 7,063 | $ 4,232 |
Reportable Segments Reportable
Reportable Segments Reportable Segments Narrative (Details) - Lone Star L.L.C. [Member] | 9 Months Ended |
Sep. 30, 2015 | |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% |
Regency [Member] | |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 30.00% |
Consolidating Guarantor Finan76
Consolidating Guarantor Financial Information Guarantor Balance Sheet Information(Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Dec. 31, 2013 |
Cash and cash equivalents | $ 858 | $ 663 | $ 1,075 | $ 568 |
All other current assets | 4,467 | 5,380 | ||
Property, plant, and equipment, net | 42,821 | 38,907 | ||
Investment in Subsidiaries | 0 | 0 | ||
Advances to and investments in unconsolidated affiliates | 5,119 | 3,760 | ||
All other assets | 10,880 | 13,964 | ||
Total assets | 64,145 | 62,674 | ||
Current liabilities | 4,483 | 6,684 | ||
Non-current liabilities | 32,598 | 30,679 | ||
Noncontrolling interest | 5,990 | 5,153 | ||
Predecessor Equity | 0 | 8,088 | ||
Total partners’ capital | 21,074 | 12,070 | ||
Total liabilities and equity | 64,145 | 62,674 | ||
Parent [Member] | ||||
Cash and cash equivalents | (1) | 17 | 266 | 0 |
All other current assets | 4,243 | 273 | ||
Property, plant, and equipment, net | 171 | 103 | ||
Investment in Subsidiaries | 40,498 | 24,361 | ||
Advances to and investments in unconsolidated affiliates | 23 | 63 | ||
All other assets | 2,335 | 3,826 | ||
Total assets | 47,269 | 28,643 | ||
Current liabilities | 395 | 1,117 | ||
Non-current liabilities | 20,889 | 11,561 | ||
Noncontrolling interest | 0 | 0 | ||
Predecessor Equity | 0 | |||
Total partners’ capital | 25,985 | 15,965 | ||
Total liabilities and equity | 47,269 | 28,643 | ||
Issuer [Member] | ||||
Cash and cash equivalents | 0 | 0 | 0 | 0 |
All other current assets | 0 | 0 | ||
Property, plant, and equipment, net | 0 | 0 | ||
Investment in Subsidiaries | 0 | 19,829 | ||
Advances to and investments in unconsolidated affiliates | 0 | 0 | ||
All other assets | 0 | 0 | ||
Total assets | 0 | 19,829 | ||
Current liabilities | 0 | 0 | ||
Non-current liabilities | 0 | 5,185 | ||
Noncontrolling interest | 0 | 0 | ||
Predecessor Equity | 14,644 | |||
Total partners’ capital | 0 | 0 | ||
Total liabilities and equity | 0 | 19,829 | ||
Guarantor Subsidiaries [Member] | ||||
Cash and cash equivalents | (14) | 0 | 0 | 0 |
All other current assets | 541 | 667 | ||
Property, plant, and equipment, net | 9,402 | 8,948 | ||
Investment in Subsidiaries | 682 | 0 | ||
Advances to and investments in unconsolidated affiliates | 979 | 2,252 | ||
All other assets | 4,529 | 4,765 | ||
Total assets | 16,119 | 16,632 | ||
Current liabilities | 1,113 | 723 | ||
Non-current liabilities | 63 | 1,575 | ||
Noncontrolling interest | 0 | 0 | ||
Predecessor Equity | 14,334 | |||
Total partners’ capital | 14,943 | 0 | ||
Total liabilities and equity | 16,119 | 16,632 | ||
Non-Guarantor Subsidiaries [Member] | ||||
Cash and cash equivalents | 880 | 654 | 820 | 568 |
All other current assets | (317) | 4,587 | ||
Property, plant, and equipment, net | 33,328 | 30,094 | ||
Investment in Subsidiaries | 0 | 6,755 | ||
Advances to and investments in unconsolidated affiliates | 3,865 | 2,441 | ||
All other assets | 4,016 | 10,047 | ||
Total assets | 41,772 | 54,578 | ||
Current liabilities | 2,979 | 5,073 | ||
Non-current liabilities | 11,646 | 16,952 | ||
Noncontrolling interest | 5,782 | 60 | ||
Predecessor Equity | 358 | |||
Total partners’ capital | 21,365 | 32,135 | ||
Total liabilities and equity | 41,772 | 54,578 | ||
Adjustments And Eliminations [Member] | ||||
Cash and cash equivalents | (7) | (8) | $ (11) | $ 0 |
All other current assets | 0 | (147) | ||
Property, plant, and equipment, net | (80) | (238) | ||
Investment in Subsidiaries | (41,180) | (50,945) | ||
Advances to and investments in unconsolidated affiliates | 252 | (996) | ||
All other assets | 0 | (4,674) | ||
Total assets | (41,015) | (57,008) | ||
Current liabilities | (4) | (229) | ||
Non-current liabilities | 0 | (4,594) | ||
Noncontrolling interest | 208 | 5,093 | ||
Predecessor Equity | (21,248) | |||
Total partners’ capital | (41,219) | (36,030) | ||
Total liabilities and equity | $ (41,015) | $ (57,008) |
Consolidating Guarantor Finan77
Consolidating Guarantor Financial Information Guarantor Statements of Operations (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Revenues | $ 6,601 | $ 14,933 | $ 28,467 | $ 42,048 |
Operating costs, expenses, and other | 6,025 | 14,123 | 26,395 | 39,764 |
OPERATING INCOME | 576 | 810 | 2,072 | 2,284 |
Interest expense, net of interest capitalized | (333) | (299) | (979) | (868) |
Equity in earnings of unconsolidated affiliates | 214 | 84 | 388 | 265 |
Losses on Extinguishments of Debt | (10) | 0 | (43) | 0 |
Gain on sale of AmeriGas common units | 0 | 14 | 0 | 177 |
Losses on interest rate derivatives | (64) | (25) | (14) | (73) |
Income (loss) before income taxes | 32 | (15) | 56 | (36) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 415 | 569 | 1,480 | 1,749 |
Income tax expense (benefit) from continuing operations | 22 | 55 | (20) | 271 |
Income from continuing operations | 393 | 514 | 1,500 | 1,478 |
Income from discontinued operations | 0 | 0 | 0 | 66 |
Net income | 393 | 514 | 1,500 | 1,544 |
Less: Net income (loss) attributable to noncontrolling interest | (24) | 78 | 182 | 219 |
Less: Net loss attributable to predecessor | 0 | 94 | (34) | 97 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 417 | 342 | 1,352 | 1,228 |
Other comprehensive income (loss) | 0 | 2 | 42 | (7) |
Comprehensive income | 393 | 516 | 1,542 | 1,537 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | (24) | 78 | 182 | 219 |
Comprehensive loss attributable to predecessor | 0 | 94 | (34) | 97 |
Comprehensive income attributable to partners | 417 | 344 | 1,394 | 1,221 |
Parent [Member] | ||||
Revenues | 0 | 0 | 0 | 0 |
Operating costs, expenses, and other | (6) | (17) | (25) | (53) |
OPERATING INCOME | 6 | 17 | 25 | 53 |
Interest expense, net of interest capitalized | (264) | (172) | (622) | (521) |
Equity in earnings of unconsolidated affiliates | 504 | 474 | 1,245 | 1,459 |
Losses on Extinguishments of Debt | (9) | (9) | ||
Gain on sale of AmeriGas common units | 14 | 177 | ||
Losses on interest rate derivatives | (64) | (25) | (14) | (60) |
Income (loss) before income taxes | 251 | 42 | 731 | 124 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 424 | 350 | 1,356 | 1,232 |
Income tax expense (benefit) from continuing operations | 7 | 10 | 4 | 4 |
Income from continuing operations | 417 | 340 | 1,352 | 1,228 |
Income from discontinued operations | 0 | 0 | 0 | |
Net income | 417 | 340 | 1,352 | 1,228 |
Less: Net income (loss) attributable to noncontrolling interest | 0 | 0 | 0 | 0 |
Less: Net loss attributable to predecessor | 0 | 0 | 0 | |
NET INCOME ATTRIBUTABLE TO PARTNERS | 417 | 340 | 1,352 | 1,228 |
Other comprehensive income (loss) | 0 | 2 | 42 | (7) |
Comprehensive income | 417 | 342 | 1,394 | 1,221 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | 0 | 0 | 0 | 0 |
Comprehensive loss attributable to predecessor | 0 | 0 | 0 | |
Comprehensive income attributable to partners | 417 | 342 | 1,394 | 1,221 |
Issuer [Member] | ||||
Revenues | 0 | 0 | 0 | 0 |
Operating costs, expenses, and other | 0 | 0 | 1 | 0 |
OPERATING INCOME | 0 | 0 | (1) | 0 |
Interest expense, net of interest capitalized | (23) | (85) | (173) | (206) |
Equity in earnings of unconsolidated affiliates | 0 | 327 | 106 | 327 |
Losses on Extinguishments of Debt | (1) | (22) | ||
Gain on sale of AmeriGas common units | 0 | 0 | ||
Losses on interest rate derivatives | 0 | 0 | 0 | 0 |
Income (loss) before income taxes | 0 | 1 | 2 | (7) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | (24) | 243 | (88) | 114 |
Income tax expense (benefit) from continuing operations | (1) | 2 | (4) | 3 |
Income from continuing operations | (23) | 241 | (84) | 111 |
Income from discontinued operations | 0 | 0 | 0 | |
Net income | (23) | 241 | (84) | 111 |
Less: Net income (loss) attributable to noncontrolling interest | 0 | 0 | 0 | 0 |
Less: Net loss attributable to predecessor | 0 | 0 | 0 | |
NET INCOME ATTRIBUTABLE TO PARTNERS | (23) | 241 | (84) | 111 |
Other comprehensive income (loss) | 0 | 0 | 0 | 0 |
Comprehensive income | (23) | 241 | (84) | 111 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | 0 | 0 | 0 | 0 |
Comprehensive loss attributable to predecessor | 0 | 0 | 0 | |
Comprehensive income attributable to partners | (23) | 241 | (84) | 111 |
Guarantor Subsidiaries [Member] | ||||
Revenues | 909 | 1,467 | 2,778 | 3,478 |
Operating costs, expenses, and other | 894 | 1,334 | 2,758 | 3,306 |
OPERATING INCOME | 15 | 133 | 20 | 172 |
Interest expense, net of interest capitalized | 6 | (1) | 7 | (14) |
Equity in earnings of unconsolidated affiliates | 25 | 20 | 69 | 60 |
Losses on Extinguishments of Debt | 0 | (12) | ||
Gain on sale of AmeriGas common units | 0 | 0 | ||
Losses on interest rate derivatives | 0 | 0 | 0 | 0 |
Income (loss) before income taxes | 1 | 0 | 2 | 3 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 47 | 152 | 86 | 221 |
Income tax expense (benefit) from continuing operations | 0 | 2 | 0 | 0 |
Income from continuing operations | 47 | 150 | 86 | 221 |
Income from discontinued operations | 32 | 48 | 83 | |
Net income | 47 | 182 | 134 | 304 |
Less: Net income (loss) attributable to noncontrolling interest | 0 | 0 | 0 | 0 |
Less: Net loss attributable to predecessor | 0 | 0 | 0 | |
NET INCOME ATTRIBUTABLE TO PARTNERS | 47 | 182 | 134 | 304 |
Other comprehensive income (loss) | 0 | 0 | 0 | 0 |
Comprehensive income | 47 | 182 | 134 | 304 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | 0 | 0 | 0 | 0 |
Comprehensive loss attributable to predecessor | 0 | 0 | 0 | |
Comprehensive income attributable to partners | 47 | 182 | 134 | 304 |
Non-Guarantor Subsidiaries [Member] | ||||
Revenues | 5,682 | 13,468 | 25,691 | 38,573 |
Operating costs, expenses, and other | 5,129 | 12,810 | 23,666 | 36,518 |
OPERATING INCOME | 553 | 658 | 2,025 | 2,055 |
Interest expense, net of interest capitalized | (91) | (95) | (331) | (276) |
Equity in earnings of unconsolidated affiliates | 128 | (139) | 408 | 181 |
Losses on Extinguishments of Debt | 0 | 0 | ||
Gain on sale of AmeriGas common units | 0 | 0 | ||
Losses on interest rate derivatives | 0 | 0 | 0 | (13) |
Income (loss) before income taxes | (182) | (5) | (540) | (8) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 408 | 419 | 1,562 | 1,939 |
Income tax expense (benefit) from continuing operations | 16 | 41 | (20) | 264 |
Income from continuing operations | 392 | 378 | 1,582 | 1,675 |
Income from discontinued operations | 0 | 0 | 66 | |
Net income | 392 | 378 | 1,582 | 1,741 |
Less: Net income (loss) attributable to noncontrolling interest | (40) | 74 | 170 | 208 |
Less: Net loss attributable to predecessor | 94 | (34) | 97 | |
NET INCOME ATTRIBUTABLE TO PARTNERS | 432 | 210 | 1,446 | 1,436 |
Other comprehensive income (loss) | 84 | (16) | 42 | (7) |
Comprehensive income | 476 | 362 | 1,624 | 1,734 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | (40) | 74 | 170 | 208 |
Comprehensive loss attributable to predecessor | 94 | (34) | 97 | |
Comprehensive income attributable to partners | 516 | 194 | 1,488 | 1,429 |
Adjustments And Eliminations [Member] | ||||
Revenues | 10 | (2) | (2) | (3) |
Operating costs, expenses, and other | 8 | (4) | (5) | (7) |
OPERATING INCOME | 2 | 2 | 3 | 4 |
Interest expense, net of interest capitalized | 39 | 54 | 140 | 149 |
Equity in earnings of unconsolidated affiliates | (443) | (598) | (1,440) | (1,762) |
Losses on Extinguishments of Debt | 0 | 0 | ||
Gain on sale of AmeriGas common units | 0 | 0 | ||
Losses on interest rate derivatives | 0 | 0 | 0 | 0 |
Income (loss) before income taxes | (38) | (53) | (139) | (148) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | (440) | (595) | (1,436) | (1,757) |
Income tax expense (benefit) from continuing operations | 0 | 0 | 0 | 0 |
Income from continuing operations | (440) | (595) | (1,436) | (1,757) |
Income from discontinued operations | (32) | (48) | (83) | |
Net income | (440) | (627) | (1,484) | (1,840) |
Less: Net income (loss) attributable to noncontrolling interest | 16 | 4 | 12 | 11 |
Less: Net loss attributable to predecessor | 0 | 0 | 0 | |
NET INCOME ATTRIBUTABLE TO PARTNERS | (456) | (631) | (1,496) | (1,851) |
Other comprehensive income (loss) | (84) | 16 | (42) | 7 |
Comprehensive income | (524) | (611) | (1,526) | (1,833) |
Less: Comprehensive income (loss) attributable to noncontrolling interest | 16 | 4 | 12 | 11 |
Comprehensive loss attributable to predecessor | 0 | 0 | 0 | |
Comprehensive income attributable to partners | $ (540) | $ (615) | $ (1,538) | $ (1,844) |
Consolidating Guarantor Finan78
Consolidating Guarantor Financial Information Guarantor Cash Flow Information (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Net Cash Provided by (Used in) Operating Activities | $ 1,993 | $ 2,468 |
Net Cash Provided by (Used in) Investing Activities | (5,151) | (4,535) |
Net Cash Provided by (Used in) Financing Activities | 3,353 | 2,574 |
Increase in cash and cash equivalents | 195 | 507 |
Cash at beginning of period | 663 | 568 |
Cash at end of period | 858 | 1,075 |
Parent [Member] | ||
Net Cash Provided by (Used in) Operating Activities | (3,435) | 790 |
Net Cash Provided by (Used in) Investing Activities | 999 | (310) |
Net Cash Provided by (Used in) Financing Activities | 2,418 | (214) |
Increase in cash and cash equivalents | (18) | 266 |
Cash at beginning of period | 17 | 0 |
Cash at end of period | (1) | 266 |
Issuer [Member] | ||
Net Cash Provided by (Used in) Operating Activities | (175) | (216) |
Net Cash Provided by (Used in) Investing Activities | 0 | (952) |
Net Cash Provided by (Used in) Financing Activities | 175 | 1,168 |
Increase in cash and cash equivalents | 0 | 0 |
Cash at beginning of period | 0 | 0 |
Cash at end of period | 0 | 0 |
Guarantor Subsidiaries [Member] | ||
Net Cash Provided by (Used in) Operating Activities | 208 | 529 |
Net Cash Provided by (Used in) Investing Activities | (893) | (564) |
Net Cash Provided by (Used in) Financing Activities | 671 | 35 |
Increase in cash and cash equivalents | (14) | 0 |
Cash at beginning of period | 0 | 0 |
Cash at end of period | (14) | 0 |
Non-Guarantor Subsidiaries [Member] | ||
Net Cash Provided by (Used in) Operating Activities | 5,593 | 3,063 |
Net Cash Provided by (Used in) Investing Activities | (5,109) | (2,498) |
Net Cash Provided by (Used in) Financing Activities | (258) | (313) |
Increase in cash and cash equivalents | 226 | 252 |
Cash at beginning of period | 654 | 568 |
Cash at end of period | 880 | 820 |
Adjustments And Eliminations [Member] | ||
Net Cash Provided by (Used in) Operating Activities | (198) | (1,698) |
Net Cash Provided by (Used in) Investing Activities | (148) | (211) |
Net Cash Provided by (Used in) Financing Activities | 347 | 1,898 |
Increase in cash and cash equivalents | 1 | (11) |
Cash at beginning of period | (8) | 0 |
Cash at end of period | $ (7) | $ (11) |