Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Feb. 18, 2015 | Jun. 30, 2014 | |
Document Information [Line Items] | |||
Entity Current Reporting Status | Yes | ||
Document Type | 8-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2014 | ||
Entity Registrant Name | Energy Transfer Partners, L.P. | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Central Index Key | 1,012,569 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 357,487,778 | ||
Entity Public Float | $ 16,930 | ||
Entity Common Stock, Shares Outstanding | 2,014 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 663 | $ 568 |
Accounts receivable, net | 3,360 | 3,658 |
Accounts receivable from related companies | 139 | 117 |
Inventories | 1,460 | 1,807 |
Exchanges receivable | 44 | 67 |
Price risk management assets | 81 | 39 |
Other current assets | 296 | 311 |
Total current assets | 6,043 | 6,567 |
PROPERTY, PLANT AND EQUIPMENT | 43,404 | 33,449 |
ACCUMULATED DEPRECIATION AND DEPLETION | (4,497) | (3,113) |
PROPERTY, PLANT AND EQUIPMENT, net | 38,907 | 30,336 |
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 3,760 | 4,050 |
NON-CURRENT PRICE RISK MANAGEMENT ASSETS | 10 | 18 |
GOODWILL | 7,642 | 5,856 |
INTANGIBLE ASSETS, net | 5,526 | 2,250 |
OTHER NON-CURRENT ASSETS, net | 786 | 823 |
Total assets | 62,674 | 49,900 |
CURRENT LIABILITIES: | ||
Drafts Payable | 15 | 98 |
Accounts payable | 3,333 | 3,735 |
Accounts payable to related companies | 25 | 25 |
Exchanges payable | 183 | 285 |
Price risk management liabilities | 21 | 53 |
Accrued and other current liabilities | 2,099 | 1,634 |
Current maturities of long-term debt | 1,008 | 637 |
Total current liabilities | 6,684 | 6,467 |
LONG-TERM DEBT, less current maturities | 24,973 | 19,761 |
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES | 154 | 73 |
DEFERRED INCOME TAXES | 4,246 | 3,784 |
OTHER NON-CURRENT LIABILITIES | 1,258 | 1,089 |
Temporary Equity, Carrying Amount, Attributable to Parent | 33 | 32 |
REDEEMABLE NONCONTROLLING INTERESTS | 15 | 0 |
EQUITY: | ||
General Partner | 184 | 171 |
Limited Partners: | ||
Common Unitholders (355,510,227 and 333,826,372 units authorized, issued and outstanding as of December 31, 2014 and 2013, respectively) | 10,430 | 9,797 |
Class E Unitholders (8,853,832 units authorized, issued and outstanding – held by subsidiary) | 0 | 0 |
Class G Unitholders (90,706,000 units authorized, issued and outstanding – held by subsidiary) | 0 | 0 |
Class H Unitholders (50,160,000 units authorized, issued and outstanding) | 1,512 | 1,511 |
Predecessor Equity | 8,088 | 3,374 |
Accumulated other comprehensive income (loss) | (56) | 61 |
Total partners’ capital | 12,070 | 11,540 |
Noncontrolling interest | 5,153 | 3,780 |
Total equity | 25,311 | 18,694 |
Total liabilities and equity | $ 62,674 | $ 49,900 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2014 | Dec. 31, 2013 |
Common Units | ||
Units - Authorized | 355,510,227 | 333,826,372 |
Units - Issued | 355,510,227 | 333,826,372 |
Units - Outstanding | 355,510,227 | 333,826,372 |
Class E Units | ||
Units - Authorized | 8,853,832 | 8,853,832 |
Units - Issued | 8,853,832 | 8,853,832 |
Units - Outstanding | 8,853,832 | 8,853,832 |
Class G Units | ||
Units - Authorized | 90,706,000 | 90,706,000 |
Units - Issued | 90,706,000 | 90,706,000 |
Units - Outstanding | 90,706,000 | 90,706,000 |
Class H Units | ||
Units - Authorized | 50,160,000 | 50,160,000 |
Units - Issued | 50,160,000 | 50,160,000 |
Units - Outstanding | 50,160,000 | 50,160,000 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
REVENUES: | |||
Natural gas sales | $ 5,386 | $ 3,842 | $ 2,704 |
NGL sales | 5,845 | 3,618 | 2,253 |
Crude sales | 16,416 | 15,477 | 2,872 |
Gathering, transportation and other fees | 3,517 | 3,097 | 2,387 |
Refined product sales | 19,437 | 18,479 | 5,299 |
Other | 4,874 | 3,822 | 1,449 |
Total revenues | 55,475 | 48,335 | 16,964 |
COSTS AND EXPENSES: | |||
Cost of products sold | 48,389 | 42,554 | 13,088 |
Operating expenses | 2,084 | 1,695 | 1,117 |
Depreciation, depletion and amortization | 1,669 | 1,296 | 858 |
Selling, general and administrative | 520 | 482 | 476 |
Goodwill impairment | 370 | 689 | 0 |
Total costs and expenses | 53,032 | 46,716 | 15,539 |
OPERATING INCOME | 2,443 | 1,619 | 1,425 |
OTHER INCOME (EXPENSE): | |||
Interest expense, net of interest capitalized | (1,165) | (1,013) | (788) |
Equity in earnings of unconsolidated affiliates | 332 | 236 | 212 |
Gain on deconsolidation of Propane Business | 0 | 0 | 1,057 |
Gain on sale of AmeriGas common units | 177 | 87 | 0 |
Loss on extinguishment of debt | (25) | (7) | (124) |
Gains (losses) on interest rate derivatives | (157) | 44 | (4) |
Non-operating environmental remediation | 0 | (168) | 0 |
Other, net | (12) | 12 | 39 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 1,593 | 810 | 1,817 |
Income tax expense from continuing operations | 358 | 97 | 63 |
INCOME FROM CONTINUING OPERATIONS | 1,235 | 713 | 1,754 |
Income (loss) from discontinued operations | 64 | 33 | (109) |
NET INCOME | 1,299 | 746 | 1,645 |
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | 116 | 255 | 37 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 1,336 | 456 | 1,569 |
GENERAL PARTNER’S INTEREST IN NET INCOME | 513 | 506 | 461 |
CLASS H UNITHOLDER’S INTEREST IN NET INCOME | 217 | 48 | 0 |
Net Income (Loss) Allocated to Predecessor Equity | (153) | 35 | 39 |
Comprehensive Income Attributable to Predecessor Equity | (153) | 35 | 41 |
COMMON UNITHOLDERS’ INTEREST IN NET INCOME (LOSS) | $ 606 | $ (98) | $ 1,108 |
INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT: | |||
Basic income (loss) from continuing operations per Common Unit | $ 1.58 | $ (0.23) | $ 4.93 |
Diluted income (loss) from continuing operations per Common Unit | 1.58 | (0.23) | 4.91 |
NET INCOME (LOSS) PER COMMON UNIT: | |||
Basic | 1.77 | (0.18) | 4.43 |
Diluted | $ 1.77 | $ (0.18) | $ 4.42 |
Noncontrolling Interest | |||
OTHER INCOME (EXPENSE): | |||
NET INCOME | $ 116 | $ 255 | $ 37 |
General Partner | |||
OTHER INCOME (EXPENSE): | |||
NET INCOME | 513 | 506 | 461 |
Class H Units | |||
OTHER INCOME (EXPENSE): | |||
NET INCOME | $ 217 | 48 | 0 |
CLASS H UNITHOLDER’S INTEREST IN NET INCOME | $ 0 | $ 0 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Net income | $ 1,299 | $ 746 | $ 1,645 |
Other comprehensive income (loss), net of tax: | |||
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges | 3 | (4) | (16) |
Change in value of derivative instruments accounted for as cash flow hedges | 0 | (1) | 12 |
Change in value of available-for-sale securities | 1 | 2 | 0 |
Actuarial gain (loss) relating to pension and other postretirement benefits | (113) | 66 | (10) |
Foreign currency translation adjustment | (2) | (1) | 0 |
Change in other comprehensive income from unconsolidated affiliates | (6) | 17 | (9) |
Total other comprehensive income | (117) | 79 | (23) |
Comprehensive income | 1,182 | 825 | 1,622 |
Less: Comprehensive income attributable to noncontrolling interest | 116 | 255 | 31 |
Comprehensive Income Attributable to Predecessor Equity | (153) | 35 | 41 |
Net Income (Loss) Allocated to Predecessor Equity | (153) | 35 | 39 |
Comprehensive income attributable to partners | $ 1,219 | $ 535 | $ 1,550 |
CONSOLIDATED STATEMENT OF EQUIT
CONSOLIDATED STATEMENT OF EQUITY - USD ($) $ in Millions | Total | General Partner | Common Unitholders | Class H Units | Accumulated Other Comprehensive Income (Loss) | Predecessor Equity [Member] | Noncontrolling Interest |
Balance at Dec. 31, 2011 | $ 9,247 | $ 182 | $ 5,533 | $ 0 | $ 6 | $ 3,493 | $ 33 |
Increase (Decrease) in Unitholders' Equity | |||||||
Distributions to partners | (1,343) | (454) | (889) | 0 | 0 | 0 | 0 |
Predecessor Distributions to Partners | (322) | 0 | 0 | 0 | 0 | (322) | 0 |
Distributions to noncontrolling interest | (165) | 0 | 0 | 0 | 0 | 0 | (165) |
Units issued for cash | 791 | 0 | 791 | 0 | 0 | 0 | 0 |
Predecessor Equity Offerings, Net of Issue Costs | 312 | 0 | 0 | 0 | 0 | 312 | 0 |
Capital contributions from noncontrolling interest | 42 | 0 | 0 | 0 | 0 | 0 | 42 |
Sunoco Merger | 5,868 | 0 | 2,288 | 0 | 0 | 0 | 3,580 |
ETP Holdco Transaction | 3,913 | 0 | 165 | 0 | 0 | 0 | 3,748 |
Issuance of units in other acquisitions (excluding Sunoco, Inc.) | 7 | 0 | 7 | 0 | 0 | 0 | 0 |
Lake Charles LNG Transaction | 0 | ||||||
Other comprehensive loss, net of tax | (23) | 0 | 0 | 0 | (19) | 2 | (6) |
Other, net | 10 | (1) | 23 | 0 | 0 | (3) | (9) |
Net income | 1,645 | 461 | 1,108 | 0 | 0 | 39 | 37 |
CLASS H UNITHOLDER’S INTEREST IN NET INCOME | 0 | 0 | |||||
Net Income (Loss) Allocated to General Partners | (461) | ||||||
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | 37 | ||||||
Balance at Dec. 31, 2012 | 19,982 | 188 | 9,026 | 0 | (13) | 3,521 | 7,260 |
Increase (Decrease) in Unitholders' Equity | |||||||
Distributions to partners | (1,802) | (523) | (1,228) | (51) | 0 | 0 | 0 |
Predecessor Distributions to Partners | (342) | 0 | 0 | 0 | 0 | (342) | 0 |
Distributions to noncontrolling interest | (303) | 0 | 0 | 0 | 0 | 0 | (303) |
Units issued for cash | 1,611 | 0 | 1,611 | 0 | 0 | 0 | 0 |
Predecessor Equity Offerings, Net of Issue Costs | 149 | 0 | 0 | 0 | 0 | 149 | 0 |
Capital contributions from noncontrolling interest | 18 | 0 | 0 | 0 | 0 | 0 | 18 |
Issuance of Class H Units | 0 | 0 | (1,514) | 1,514 | 0 | 0 | 0 |
ETP Holdco Acquisition and SUGS Contribution | (1,440) | 0 | 2,013 | 0 | (5) | 0 | (3,448) |
Lake Charles LNG Transaction | 0 | ||||||
Other comprehensive loss, net of tax | 79 | 0 | 0 | 0 | 79 | 0 | 0 |
Other, net | (4) | 0 | (13) | 0 | 0 | 11 | (2) |
Net income | 746 | 506 | (98) | 48 | 0 | 35 | 255 |
CLASS H UNITHOLDER’S INTEREST IN NET INCOME | 48 | 0 | |||||
Net Income (Loss) Allocated to General Partners | (506) | ||||||
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | 255 | ||||||
Balance at Dec. 31, 2013 | 18,694 | 171 | 9,797 | 1,511 | 61 | 3,374 | 3,780 |
Increase (Decrease) in Unitholders' Equity | |||||||
Distributions to partners | (1,964) | (500) | (1,252) | (212) | 0 | 0 | 0 |
Predecessor Distributions to Partners | (645) | 0 | 0 | 0 | 0 | (645) | 0 |
Distributions to noncontrolling interest | (241) | 0 | 0 | 0 | 0 | 0 | (241) |
Units issued for cash | 1,382 | 0 | 1,382 | 0 | 0 | 0 | 0 |
Predecessor Equity Offerings, Net of Issue Costs | 1,227 | 0 | 0 | 0 | 0 | 1,227 | 0 |
Capital contributions from noncontrolling interest | 67 | 0 | 0 | 0 | 0 | 0 | 67 |
Subsidiary units issued for cash | 1,244 | 1 | 174 | 0 | 0 | 0 | 1,069 |
Lake Charles LNG Transaction | (1,167) | 0 | (1,167) | 0 | 0 | 0 | 0 |
Susser Merger | 1,534 | 0 | 908 | 0 | 0 | 0 | 626 |
Sunoco Logistics acquisition of a noncontrolling interest | (325) | (1) | (79) | 0 | 0 | 0 | (245) |
Predecessor Equity Issued in Acquisitions | Hoover Midstream Acquisition [Member] | 109 | 0 | 0 | 0 | 0 | 109 | 0 |
Predecessor Equity Issued in Acquisitions | PVR Acquisition [Member] | 3,906 | 0 | 0 | 0 | 0 | 3,906 | 0 |
Predecessor Equity Issued in Acquisitions | Eagle Rock Midstream Acquisition [Member] | 266 | 0 | 0 | 0 | 0 | 266 | 0 |
Other comprehensive loss, net of tax | (117) | 0 | 0 | 0 | (117) | 0 | 0 |
Other, net | 42 | 0 | 61 | (4) | 0 | 4 | (19) |
Net income | 1,299 | 513 | 606 | 217 | 0 | (153) | 116 |
CLASS H UNITHOLDER’S INTEREST IN NET INCOME | 217 | ||||||
Net Income (Loss) Allocated to General Partners | (513) | ||||||
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | 116 | ||||||
Balance at Dec. 31, 2014 | $ 25,311 | $ 184 | $ 10,430 | $ 1,512 | $ (56) | $ 8,088 | $ 5,153 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - Business Acquisition, Acquiree [Domain] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income | $ 1,299 | $ 746 | $ 1,645 |
Reconciliation of net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 1,669 | 1,296 | 858 |
Deferred income taxes | (49) | 48 | 62 |
Amortization included in interest expense | (60) | (72) | (28) |
Inventory valuation adjustments | 473 | (3) | 75 |
Non-cash compensation expense | 68 | 54 | 47 |
Goodwill impairment | 370 | 689 | 0 |
Gain on sale of AmeriGas common units | (177) | (87) | 0 |
Gain on deconsolidation of Propane Business | 0 | 0 | (1,057) |
Gain on curtailment of other postretirement benefits | 0 | 0 | (15) |
Loss on extinguishment of debt | 25 | 7 | 124 |
Write-down of assets included in loss from discontinued operations | 0 | 0 | 132 |
Distributions on unvested awards | (16) | (12) | (8) |
Equity in earnings of unconsolidated affiliates | (332) | (236) | (212) |
Distributions from unconsolidated affiliates | 291 | 313 | 208 |
Other non-cash | (72) | 42 | 68 |
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (320) | (158) | (493) |
Net cash provided by operating activities | 3,169 | 2,627 | 1,406 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Cash paid for Susser Merger, net of cash received (see Note 3) | 808 | 0 | 0 |
Cash paid for ETP Holdco Acquisition | 0 | (1,332) | 0 |
Cash paid for Citrus Merger | 0 | 0 | (1,895) |
Cash paid for acquisition of a noncontrolling interest | (325) | 0 | 0 |
Cash proceeds from the sale of AmeriGas common units | 814 | 346 | 0 |
Cash proceeds from contribution and sale of propane operations | 0 | 0 | 1,443 |
Cash (paid) received from all other acquisitions | (472) | (405) | 531 |
Capital expenditures (excluding allowance for equity funds used during construction) | (5,213) | (3,469) | (3,271) |
Cash (paid) received from all other acquisitions | 45 | 52 | 35 |
Contributions to unconsolidated affiliates | (399) | (3) | (65) |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 136 | 419 | 190 |
Proceeds from sale of discontinued operations | 77 | 1,008 | 207 |
Proceeds from the sale of assets | 61 | 68 | 44 |
Change in restricted cash | 172 | (348) | 5 |
Other | (18) | 21 | 112 |
Net cash used in investing activities | (6,692) | (3,643) | (2,664) |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Proceeds from borrowings | 15,354 | 10,854 | 10,762 |
Repayments of long-term debt | (12,702) | (8,700) | (8,685) |
Proceeds from borrowings from affiliates | 0 | 0 | 221 |
Repayments of borrowings from affiliates | 0 | (166) | (55) |
Net proceeds from issuance of Common Units | 1,382 | 1,611 | 791 |
Subsidiary equity offerings, net of issue costs | 1,244 | 0 | 0 |
Predecessor Equity Offerings, Net of Issue Costs | 1,227 | 149 | 312 |
Capital contributions received from noncontrolling interest | 67 | 18 | 42 |
Distributions to partners | (1,964) | (1,802) | (1,343) |
Predecessor Distributions to Partners | (645) | (342) | (322) |
Distributions to noncontrolling interest | (241) | (303) | (165) |
Debt issuance costs | (63) | (57) | (35) |
Other | (41) | (42) | (8) |
Net cash provided by financing activities | 3,618 | 1,220 | 1,515 |
INCREASE IN CASH AND CASH EQUIVALENTS | 95 | 204 | 257 |
CASH AND CASH EQUIVALENTS, beginning of period | 568 | 364 | 107 |
CASH AND CASH EQUIVALENTS, end of period | 663 | 568 | 364 |
Eagle Rock Midstream Acquisition [Member] | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Predecessor Cash Paid For Acquisitions | (577) | 0 | 0 |
Hoover Midstream Acquisition [Member] | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Predecessor Cash Paid For Acquisitions | $ (185) | $ 0 | $ 0 |
Operations and Organization (No
Operations and Organization (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Operations And Organization [Abstract] | |
OPERATIONS AND ORGANIZATION | OPERATIONS AND ORGANIZATION: The consolidated financial statements and notes thereto of Energy Transfer Partners, L.P., and its subsidiaries (the “Partnership,” “we” or “ETP”) presented herein for the years ended December 31, 2014, 2013 and 2012 , have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and subsidiaries we control, even if we do not have a majority ownership. All significant intercompany transactions and accounts are eliminated in consolidation. Management has evaluated subsequent events through the date the financial statements were issued. We also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these assets. Certain prior period amounts have been reclassified to conform to the 2014 presentation. These reclassifications had no impact on net income or total equity. As discussed in Note 3, ETP and Regency merged in April 2015. ETP and Regency were under common control of ETE; therefore, we accounted for the Regency Merger at historical cost as a reorganization of entities under common control. In accordance with GAAP, ETP’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. We 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 general partner of our General Partner. The consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below. Our consolidated subsidiary, Susser Petroleum Partners LP, changed its name in October 2014 to Sunoco LP. Additionally, Trunkline LNG Company, LLC, a consolidated subsidiary of ETE, changed its name in September 2014 to Lake Charles LNG Company, LLC. All references to these entities throughout this document reflect the new name of these entities, regardless of whether the disclosure relates to periods or events prior to the dates of the name changes. Business Operations 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. ETC OLP also owns 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. As discussed in Note 3 , in January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger. • 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 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. • ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 42.8% limited partner interest in Sunoco LP as of December 31, 2014. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas and Louisiana and other commercial customers. As discussed in Note 3 , in October 2014, Sunoco LP acquired MACS from ETP. These operations are reported within the retail marketing segment. • Regency is a limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs (until June 1, 2015); the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; natural gas and NGL marketing and trading, and the management of coal and natural resource properties in the United States. Regency 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. |
Estimates, Significant Accounti
Estimates, Significant Accounting Policies and Balance Sheet Detials (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |
Estimates Significant Accounting Policies And Balance Sheet Detail Text Block | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. New Accounting Pronouncements In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810) (“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. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies. In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations. Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed. Revenue Recognition Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues. Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer. In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations. Our retail marketing segment sells gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease with the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured. Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas, NGL, condensate and salt water gathering, processing and transportation, (iii) contract compression and treating services and (iv) coal royalties. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression and contract treating services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas and NGLs at a price approximating the index price to third parties. Regency generally reports revenue gross in the consolidated statements of operations when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification. Regency recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. Regency does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. Regency records any differences between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most lessees must make minimum monthly or annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned. Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs. Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. The net change in operating assets and liabilities (net of acquisitions) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2014 2013 2012 Accounts receivable $ 600 $ (557 ) $ 267 Accounts receivable from related companies (22 ) 26 (12 ) Inventories 51 (254 ) (258 ) Exchanges receivable 18 (8 ) 14 Other current assets 132 (58 ) 574 Other non-current assets, net (6 ) (45 ) (30 ) Accounts payable (851 ) 542 (990 ) Accounts payable to related companies 3 (143 ) 101 Exchanges payable (99 ) 128 — Accrued and other current liabilities (92 ) 211 (169 ) Other non-current liabilities (73 ) 147 25 Price risk management assets and liabilities, net 19 (147 ) (15 ) Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (320 ) $ (158 ) $ (493 ) Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2014 2013 2012 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 643 $ 226 $ 420 Net gains from subsidiary common unit issuances $ 175 $ — $ — AmeriGas limited partner interest received in exchange for contribution of Propane Business $ — $ — $ 1,123 NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the Susser Merger (see Note 3) $ 908 $ — $ — Redemption of Common Units in connection with the Lake Charles LNG Transaction (see Note 3) $ 1,167 $ — $ — Issuance of Common Units in connection with the ETP Holdco Acquisition $ — $ 2,464 $ — Issuance of Class H Units $ — $ 1,514 $ — Long-term debt assumed and non-compete agreement notes payable issued in acquisitions $ 564 $ — $ 6,658 Issuance of Common Units in connection with other acquisitions $ — $ — $ 2,295 Predecessor equity issuance of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions $ 4,281 $ — $ — Long-term debt assumed in PVR Acquisition $ 1,887 $ — $ — Long-term debt exchanged in Eagle Rock Midstream Acquisition $ 499 $ — $ — SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,232 $ 1,049 $ 790 Cash paid for income taxes $ 344 $ 58 $ 23 Accounts Receivable Our midstream, NGL and intrastate transportation and storage operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned for all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. Master setoff agreements are put in place with counterparties where appropriate to mitigate risk. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Based on that review, a letter of credit or other security may be required. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted. Our interstate transportation and storage operations have a concentration of customers in the electric and gas utility industries, municipalities, as well as natural gas producers. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral. Management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Our interstate transportation and storage operations establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectability. Our retail marketing segment extends credit to customers after a review of various credit indicators. Depending on the type of customer and its risk profile, security in the form of a cash deposit, letter of credit or mortgages may be required. Management records reserves for bad debt by computing a proportion of average write-off activity over the past five years in comparison to the outstanding balance in accounts receivable. This proportion is then applied to the accounts receivable balance at the end of the reporting period to calculate a current estimate of what is uncollectible. The allowance computation may then be adjusted to reflect input provided by the credit department and business line managers who may have specific knowledge of uncollectible items. The credit department and business line managers make the decision to write off an account, based on understanding of the potential collectability. We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets. Inventories Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method. Inventories consisted of the following: December 31, 2014 2013 Natural gas and NGLs $ 392 $ 577 Crude oil 364 488 Refined products 392 543 Appliances, parts and fittings, and other 312 199 Total inventories $ 1,460 $ 1,807 During the year ended December 31, 2014 , the Partnership recorded write-downs of $473 million on its crude oil, refined products and NGL inventories as a result of a decline in the market price of these products. The write-down was calculated based upon current replacement costs. We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations. Exchanges Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms. Other Current Assets Other current assets consisted of the following: December 31, 2014 2013 Deposits paid to vendors $ 65 $ 49 Deferred income taxes 14 — Prepaid expenses and other 217 262 Total other current assets $ 296 $ 311 Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. We review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds. Components and useful lives of property, plant and equipment were as follows: December 31, 2014 2013 Land and improvements $ 1,307 $ 881 Buildings and improvements (1 to 45 years) 1,918 935 Pipelines and equipment (5 to 83 years) 27,164 21,038 Natural gas and NGL storage facilities (5 to 46 years) 1,215 1,083 Bulk storage, equipment and facilities (2 to 83 years) 2,583 1,933 Tanks and other equipment (5 to 40 years) 58 1,697 Retail equipment (2 to 99 years) 515 450 Vehicles (1 to 25 years) 203 156 Right of way (20 to 83 years) 2,445 2,183 Furniture and fixtures (2 to 25 years) 57 51 Linepack 119 118 Pad gas 44 52 Natural resources 454 — Other (1 to 30 years) 979 706 Construction work-in-process 4,343 2,166 43,404 33,449 Less – Accumulated depreciation (4,497 ) (3,113 ) Property, plant and equipment, net $ 38,907 $ 30,336 We recognized the following amounts of depreciation expense for the periods presented: Years Ended December 31, 2014 2013 2012 Depreciation expense $ 1,459 $ 1,202 $ 783 Capitalized interest, excluding AFUDC $ 101 $ 45 $ 99 Depletion expense related to Regency’s natural resources operations was $11 million for the year ended December 31, 2014. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of coal extracted as compared to the total estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by Regency’s own geologists. Regency’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, Regency carries out core-hole drilling activities on coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. Regency depletes timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. Regency determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. Advances to and Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for subsidiaries in our intrastate transportation and storage and midstream segments and during the fourth quarter for subsidiaries in our interstate transportation and storage, liquids transportation and services and retail marketing segments and all others, including all of Regency’s reporting units. We recorded goodwill impairments for the periods presented in these consolidated financial statements. Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream Liquids Transportation and Services Investment in Sunoco Logistics Retail Marketing All Other Total Balance, December 31, 2012 $ 10 $ 1,884 $ 688 $ 432 $ 1,368 $ 1,272 $ 742 $ 6,396 Goodwill acquired — — — — — 156 — 156 Goodwill impairment — (689 ) — — — — — (689 ) Other — — (2 ) — (22 ) 17 — (7 ) Balance, December 31, 2013 10 1,195 686 432 1,346 1,445 742 5,856 Goodwill acquired — — 451 — 12 1,862 15 2,340 Goodwill disposed — (184 ) — — — — — (184 ) Goodwill impairment — — (370 ) — — — — (370 ) Balance, December 31, 2014 $ 10 $ 1,011 $ 767 $ 432 $ 1,358 $ 3,307 $ 757 $ 7,642 Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. We recorded a net increase in goodwill of $1.79 billion during the year ended December 31, 2014 primarily due to the Susser Merger and PVR Acquisition where we recorded goodwill of $1.73 billion and $370 million , respectively, offset by an impairment of $370 million , as discussed below. The additional goodwill recorded during the years ended December 31, 2014 and 2013 is not expected to be deductible for tax purposes. During the fourth quarter of 2014, a $370 million goodwill impairment was recorded |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Business Combinations [Abstract] | |
ACQUISITIONS AND DIVESTITURE | ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: 2015 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, Sunoco LP acquired 100% of Susser from ETP in a transaction valued at $1.93 billion . Sunoco LP paid approximately $967 million in cash and issued 22 million Sunoco LP common units, valued at approximately $967 million , to ETP. In addition, there will be an exchange for 11 million Sunoco LP units owned by Susser for another 11 million new Sunoco LP units to a subsidiary of ETP. In July 2015, ETE entered into an exchange and repurchase agreement with ETP, pursuant to which ETE would acquire 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, in exchange for the repurchase of 21 million ETP common units owned by ETE. 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 agreed to provide ETP a $35 million annual IDR subsidy for two years. Following this transaction, Sunoco LP will no longer be consolidated for accounting purposes by ETP. This transaction is expected to close in August 2015. Regency Merger In April 2015, ETP and Regency completed the previously announced merger of an indirect subsidiary of ETP, with and into Regency, with Regency surviving the merger as a wholly-owned subsidiary of ETP (the “Regency Merger”). As part of the merger consideration, each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP Common Units. Based on the Regency units outstanding, ETP issued approximately 172.2 million ETP Common Units to Regency unitholders, including approximately 15.5 million units issued to ETP subsidiaries. The approximately 1.9 million outstanding Regency series A preferred units were concerted into corresponding new ETP Series A Preferred Units. In connection with the transaction, ETE, which owns the general partner and 100% of the incentive distribution rights of ETP, will reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy will be $80 million in the first year post-closing and $60 million per year for the following four years. ETP and Regency were under common control of ETE; therefore, we accounted for the Regency Merger at historical cost as a reorganization of entities under common control. In accordance with GAAP, ETP’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 (loss) for the previously separate entities and the combined amounts presented herein: Years Ended December 31, 2014 2013 2012 Revenues: Partnership $ 51,158 $ 46,339 $ 15,702 Regency 4,840 2,242 1,309 Adjustments and eliminations (523 ) (246 ) (47 ) Combined $ 55,475 $ 48,335 $ 16,964 Net income (loss): Partnership $ 1,553 $ 767 $ 1,647 Regency (142 ) 64 48 Adjustments and eliminations (112 ) (85 ) (50 ) Combined $ 1,299 $ 746 $ 1,645 2014 Transactions Susser Merger In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens our retail geographic footprint and provides synergy opportunities and a platform for future growth. In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations. Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE. Summary of Assets Acquired and Liabilities Assumed We accounted for the Susser Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet as of December 31, 2014 reflected the preliminary purchase price allocations based on available information. Management is reviewing the valuation and confirming the results to determine the final purchase price allocation. The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date: Susser Total current assets $ 446 Property, plant and equipment 1,069 Goodwill (1) 1,734 Intangible assets 611 Other non-current assets 17 3,877 Total current liabilities 377 Long-term debt, less current maturities 564 Deferred income taxes 488 Other non-current liabilities 39 Noncontrolling interest 626 2,094 Total consideration 1,783 Cash received 67 Total consideration, net of cash received $ 1,716 (1) None of the goodwill is expected to be deductible for tax purposes. The fair values of the assets acquired and liabilities assumed is being determined using various valuation techniques, including the income and market approaches. ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2014 . Our consolidated statements of operations for the year ended December 31, 2014 reflected revenue and net income related to Susser of $2.32 billion and $105 million , respectively. No pro forma information has been presented, as the impact of these acquisitions was not material in relation to ETP’s consolidated results of operations. MACS to Sunoco LP In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units. Lake Charles LNG Transaction On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). This transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG, including goodwill of $184 million and intangible assets of $50 million related to Lake Charles LNG. The results of Lake Charles LNG’s operations have not been presented as discontinued operations and Lake Charles LNG’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements due to the continuing involvement among the entities. In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 9 . Panhandle Merger On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% senior notes due 2024, 8.25% senior notes due 2029 and the junior subordinated notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency ( 31.4 million common units and 6.3 million Class F Units), and ETP ( 2.2 million Common Units). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes. Regency’s Acquisition of PVR Partners, L.P. On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million , which was funded through borrowings under Regency’s revolving credit facility. The PVR Acquisition enhances Regency’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. Regency accounted for the PVR Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million , respectively. Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows: Assets At March 21, 2014 Current assets $ 149 Property, plant and equipment 2,716 Investment in unconsolidated affiliates 62 Intangible assets (average useful life of 30 years) 2,717 Goodwill 370 Other non-current assets 18 Total assets acquired 6,032 Liabilities Current liabilities 168 Long-term debt 1,788 Premium related to senior notes 99 Non-current liabilities 30 Total liabilities assumed 2,085 Net assets acquired $ 3,947 The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. Regency’s Acquisition of Eagle Rock’s Midstream Business On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion , including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Regency accounted for the Eagle Rock Midstream Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. This acquisition complements Regency’s core gathering and processing business and further diversifies Regency’s geographic presence in the Mid-Continent region, east Texas and south Texas. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million , respectively. Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows: Assets At July 1, 2014 Current assets $ 113 Property, plant and equipment 1,295 Goodwill (1) 59 Total assets acquired 1,467 Liabilities Current liabilities 116 Long-term debt 499 Other non-current liabilities 11 Total liabilities assumed 626 Net assets acquired $ 841 (1) None of the goodwill is expected to be deductible for tax purposes. The fair values of the assets acquired and liabilities assumed is being determined using various valuation techniques, including the income and market approaches. Regency’s Acquisition of Hoover Energy On February 3, 2014, Regency completed its acquistion of certain subsidiaries of Hoover Energy for a total purchase price of $293 million , consisted of (i) 4.0 million Regency Common Units issued to Hoover Energy, (ii) $184 million in cash, and (iii) $2 million in asset retirement obligations assumed. 2013 Transactions Sale of Southern Union’s Distribution Operations In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union’s NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allowed a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division. In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million , subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million , subject to customary post-closing adjustments, and the assumption of $20 million of debt. The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations. The following table summarizes selected financial information related to Southern Union’s distribution operations in 2013 through MGE and NEG’s sale dates in September 2013 and December 2013, respectively, and for the period from March 26, 2012 to December 31, 2012: Years Ended December 31, 2013 2012 Revenue from discontinued operations $ 415 $ 324 Net income of discontinued operations, excluding effect of taxes and overhead allocations 65 43 SUGS Contribution On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). Prior to the Regency Merger, the general partner and IDRs of Regency were owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units had the same rights, terms and conditions as the Regency common units, except that Southern Union was receiving distributions on the Regency Class F units. These units converted to ETP common units on the date of the Regency Merger. Acquisition of ETE’s ETP Holdco Interest On April 30, 2013, ETP acquired ETE’s 60% interest in ETP Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “ETP Holdco Acquisition”). As a result, ETP now owns 100% of ETP Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled ETP Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control. 2012 Transactions Southern Union Merger On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union was the surviving entity in the merger and operated as a wholly-owned subsidiary of ETE. See below for discussion of ETP Holdco Transaction and ETE’s contribution of Southern Union to ETP Holdco. Under the terms of the merger agreement, Southern Union stockholders received a total of 57 million ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded. Citrus Acquisition In connection with the Southern Union Merger on March 26, 2012, we completed our acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion , consisting of approximately $1.9 billion in cash and approximately 2.2 million ETP Common Units. See Note 4 for more information regarding our equity method investment in Citrus. Sunoco Merger On October 5, 2012, ETP completed its merger with Sunoco, Inc. Under the terms of the merger agreement, Sunoco, Inc. shareholders received 55 million ETP Common Units and a total of approximately $2.6 billion in cash. Sunoco, Inc. generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco, Inc. also owned a 2% general partner interest, 100% of the IDRs, and 32% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco, Inc.’s interests in Sunoco Logistics were transferred to the Partnership. Prior to the Sunoco Merger, on September 8, 2012, Sunoco, Inc. completed the exit from its Northeast refining operations by contributing the refining assets at its Philadelphia refinery and various commercial contracts to PES, a joint venture with The Carlyle Group. Sunoco, Inc. also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook Industrial Complex continued to support operations at the Philadelphia refinery prior to commencement of the PES joint venture. Under the terms of the joint venture agreement, The Carlyle Group contributed cash in exchange for a 67% controlling interest in PES. In exchange for contributing its Philadelphia refinery assets and various commercial contracts to the joint venture, Sunoco, Inc. retained an approximate 33% non-operating noncontrolling interest. The fair value of Sunoco, Inc.’s retained interest in PES, which was $75 million on the date on which the joint venture was formed, was determined based on the equity contributions of The Carlyle Group. Sunoco, Inc. has indemnified PES for environmental liabilities related to the Philadelphia refinery that arose from the operation of such assets prior the formation of the joint venture. The Carlyle Group will oversee day-to-day operations of PES and the refinery. JPMorgan Chase provides working capital financing to PES in the form of an asset-backed loan, supply crude oil and other feedstocks to the refinery at the time of processing and purchase certain blendstocks and all finished refined products as they are processed. Sunoco, Inc. entered into a supply contract for gasoline and diesel produced at the refinery for its retail marketing business. ETP incurred merger related costs related to the Sunoco Merger of $28 million during the year ended December 31, 2012. Sunoco, Inc.’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco, Inc.’s net loss included in our consolidated statement of operations was approximately $14 million during October through December 2012. Sunoco Logistics’ revenue included in our consolidated statement of operations was approximately $3.11 billion during October through December 2012. Sunoco Logistics’ net income included in our consolidated statement of operations was approximately $145 million during October through December 2012. ETP Holdco Transaction Immediately following the closing of the Sunoco Merger in 2012, ETE contributed its interest in Southern Union into ETP Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in ETP Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco, Inc. to ETP Holdco and retained a 40% equity interest in ETP Holdco. Prior to the contribution of Sunoco, Inc. to ETP Holdco, Sunoco, Inc. contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90.7 million Class F Units representing limited partner interests in ETP (“Class F Units”). The Class F Units were exchanged for Class G Units in 2013 as discussed in Note 9 . Pursuant to a stockholders agreement between ETE and ETP, ETP controlled ETP Holdco (prior to ETP’s acquisition of ETE’s 60% equity interest in ETP Holdco in 2013) and therefore, ETP consolidated ETP Holdco (including Sunoco, Inc. and Southern Union) in its financial statements subsequent to consummation of the ETP Holdco Transaction. Under the terms of the ETP Holdco transaction agreement, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012. In accordance with GAAP, we have accounted for the ETP Holdco Transaction, whereby ETP obtained control of Southern Union, as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Southern Union into ETP beginning March 26, 2012 (the date ETE acquired Southern Union). This change only impacted interim periods in 2012, and no prior annual amounts have been adjusted. Summary of Assets Acquired and Liabilities Assumed We accounted for the Sunoco Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Upon consummation of the ETP Holdco Transaction, we applied the accounting guidance for transactions between entities under common control. In doing so, we recorded the values of assets and liabilities that had been recorded by ETE as reflected below. The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates: Sunoco, Inc. (1) Southern Union (2) Current assets $ 7,312 $ 556 Property, plant and equipment 6,686 6,242 Goodwill 2,641 2,497 Intangible assets 1,361 55 Investments in unconsolidated affiliates 240 2,023 Note receivable 821 — Other assets 128 163 19,189 11,536 Current liabilities 4,424 1,348 Long-term debt obligations, less current maturities 2,879 3,120 Deferred income taxes 1,762 1,419 Other non-current liabilities 769 284 Noncontrolling interest 3,580 — 13,414 6,171 Total consideration 5,775 5,365 Cash received 2,714 37 Total consideration, net of cash received $ 3,061 $ 5,328 (1) Includes amounts recorded with respect to Sunoco Logistics. (2) Includes ETP’s acquisition of Citrus. The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. As a result of the ETP Holdco Transaction, we recognized $38 million of merger-related costs during the year ended December 31, 2012 related to Southern Union. Southern Union’s revenue included in our consolidated statement of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statement of operations was approximately $39 million since the acquisition date to December 31, 2012. Propane Operations On January 12, 2012, we contributed our propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. We received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, we entered into a support agreement with AmeriGas pursuant to which we are obligated to provide contingent, residual support of $1.50 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.50 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price. Our consolidated financial statements did not reflect the Propane Business as discontinued operations due to our continuing involvement in this business through our investment in AmeriGas that was transferred as consideration for the transaction. In June 2012, we sold the remainder of our retail propane operations, consisting of our cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and we received net proceeds of approximately $43 million . Sale of Canyon In October 2012, we sold Canyon for approximately $207 million . The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been restated to present Canyon’s operations as discontinued operations. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $132 million during the year ended December 31, 2012. Canyon was previously included in our midstream segment. Pro Forma Results of Operations The following unaudited pro forma consolidated results of operations for the years ended December 31, 2014, 2013 and 2012 are presented as if the Sunoco Merger and the ETP Holdco Transaction had been completed on January 1, 2012, and the PVR and Eagle Rock Midstream acquisitions had been completed on January 1, 2013, and assumes there were no other changes in operations. Years Ended December 31, 2014 2013 2012 Revenues $ 56,301 $ 50,473 $ 40,397 Net income 1,151 532 1,240 Net income attributable to partners 1,323 423 817 Basic net income per Limited Partner unit $ 3.99 $ 1.23 $ 3.29 Diluted net income per Limited Partner unit $ 3.97 $ 1.23 $ 3.28 The pro forma consolidated results of operations include adjustments to: • include the results of Southern Union and Sunoco, Inc. beginning January 1, 2012; • include the results of PVR and Eagle Rock midstream beginning January 1, 2013; • include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting; • include incremental interest expense related to the financing of ETP’s proportionate share of the purchase price; and • reflect noncontrolling interest related to ETE’s 60% interest in ETP Holdco during the periods. The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations. |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 12 Months Ended |
Dec. 31, 2014 | |
Investments in and Advances to Affiliates, Schedule of Investments [Abstract] | |
Investments in and Advances to Affiliates, Schedule of Investments [Text Block] | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: Citrus On March 26, 2012, ETE consummated the acquisition of Southern Union and, concurrently with the closing of the Southern Union acquisition, CrossCountry, a subsidiary of Southern Union that indirectly owned a 50% interest in Citrus, merged with a subsidiary of ETP and, in connection therewith, ETP paid approximately $1.9 billion in cash and issued $105 million of ETP Common Units (the “Citrus Acquisition”) to a subsidiary of ETE. As a result of the consummation of the Citrus Acquisition, ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. We recorded our investment in Citrus at $2.0 billion , which exceeded our proportionate share of Citrus’ equity by $1.03 billion , all of which is treated as equity method goodwill due to the application of regulatory accounting. The carrying amount of our investment in Citrus was $1.82 billion and $1.89 billion as of December 31, 2014 and 2013 , respectively, and was reflected in our interstate transportation and storage segment. AmeriGas As discussed in Note 3 , on January 12, 2012, we received approximately 29.6 million AmeriGas common units in connection with the contribution of our propane operations. In the year ended 2013 , we sold 7.5 million AmeriGas common units for net proceeds of $346 million , and in the year ended 2014 we sold approximately 18.9 million AmeriGas common units for net proceeds of $814 million . Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and general partnership purposes. Subsequent to the sales, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company. FEP We have a 50% interest in FEP, a 50/50 joint venture with KMP. FEP owns the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The carrying amount of our investment in FEP was $130 million and $144 million as of December 31, 2014 and 2013 , respectively, and was reflected in our interstate transportation and storage segment. Midcontinent Express Pipeline LLC Regency owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. The carrying amount of Regency’s investment in MEP was $695 million and $548 million as of December 31, 2014 and 2013 , respectively, and was reflected in our interstate transportation and storage segment. RIGS Haynesville Partnership Co. Regency owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. The carrying amount of Regency’s investment in HPC was $422 million and $442 million as of December 31, 2014 and 2013 , respectively, and was reflected in our intrastate transportation and storage segment. Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented: December 31, 2014 2013 Current assets $ 889 $ 1,028 Property, plant and equipment, net 10,520 10,778 Other assets 2,687 2,664 Total assets $ 14,096 $ 14,470 Current liabilities $ 1,983 $ 1,039 Non-current liabilities 7,359 8,139 Equity 4,754 5,292 Total liabilities and equity $ 14,096 $ 14,470 Years Ended December 31, 2014 2013 2012 Revenue $ 4,925 $ 4,695 $ 4,492 Operating income 1,071 1,197 863 Net income 577 699 491 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements. |
Net Income Per Limited Partner
Net Income Per Limited Partner Unit (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Earnings Per Share [Abstract] | |
NET INCOME PER LIMITED PARTNER UNIT | 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: Years Ended December 31, 2014 2013 2012 Income from continuing operations $ 1,235 $ 713 $ 1,754 Less: Income from continuing operations attributable to noncontrolling interest 116 239 20 Less: Income (loss) from continuing operations attributable to predecessor (153 ) 35 39 Income from continuing operations, net of noncontrolling interest and predecessor income (loss) 1,272 439 1,695 General Partner’s interest in income from continuing operations 513 505 463 Class H Unitholder’s interest in income from continuing operations 217 — — Common Unitholders’ interest in income (loss) from continuing operations 542 (66 ) 1,232 Additional earnings allocated (to) from General Partner (4 ) (2 ) 1 Distributions on employee unit awards, net of allocation to General Partner (13 ) (10 ) (9 ) Income (loss) from continuing operations available to Common Unitholders $ 525 $ (78 ) $ 1,224 Weighted average Common Units – basic 331.5 343.4 248.3 Basic income (loss) from continuing operations per Common Unit $ 1.58 $ (0.23 ) $ 4.93 Dilutive effect of unvested Unit Awards 1.3 — 0.7 Weighted average Common Units, assuming dilutive effect of unvested Unit Awards 332.8 343.4 249.0 Diluted income (loss) from continuing operations per Common Unit $ 1.58 $ (0.23 ) $ 4.91 Basic income (loss) from discontinued operations per Common Unit $ 0.19 $ 0.05 $ (0.50 ) Diluted income (loss) from discontinued operations per Common Unit $ 0.19 $ 0.05 $ (0.50 ) |
Debt Obligations (Notes)
Debt Obligations (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Debt Obligations [Abstract] | |
DEBT OBLIGATIONS | DEBT OBLIGATIONS: Our debt obligations consist of the following: December 31, 2014 2013 ETP Debt 8.5% Senior Notes due April 15, 2014 $ — $ 292 5.95% Senior Notes due February 1, 2015 750 750 6.125% Senior Notes due February 15, 2017 400 400 6.7% Senior Notes due July 1, 2018 600 600 9.7% Senior Notes due March 15, 2019 400 400 9.0% Senior Notes due April 15, 2019 450 450 4.15% Senior Notes due October 1, 2020 700 700 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 3.60% Senior Notes due February 1, 2023 800 800 4.9% Senior Notes due February 1, 2024 350 350 7.6% Senior Notes due February 1, 2024 277 277 8.25% Senior Notes due November 15, 2029 267 267 6.625% Senior Notes due October 15, 2036 400 400 7.5% Senior Notes due July 1, 2038 550 550 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 ETP $2.5 billion Revolving Credit Facility due October 27, 2019 570 65 Unamortized premiums, discounts and fair value adjustments, net (1 ) (34 ) 11,459 11,213 Transwestern Debt 5.39% Senior Notes due November 17, 2014 — 88 5.54% Senior Notes due November 17, 2016 125 125 5.64% Senior Notes due May 24, 2017 82 82 5.36% Senior Notes due December 9, 2020 175 175 5.89% Senior Notes due May 24, 2022 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 Unamortized premiums, discounts and fair value adjustments, net (1 ) (1 ) 781 869 Panhandle Debt (1) 6.20% Senior Notes due November 1, 2017 300 300 7.00% Senior Notes due June 15, 2018 400 400 8.125% Senior Notes due June 1, 2019 150 150 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 14, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 99 155 1,184 1,240 Sunoco, Inc. Debt 4.875% Senior Notes due October 15, 2014 — 250 9.625% Senior Notes due April 15, 2015 250 250 5.75% Senior Notes due January 15, 2017 400 400 9.00% Debentures due November 1, 2024 65 65 Unamortized premiums, discounts and fair value adjustments, net 35 70 750 1,035 Sunoco Logistics Debt 8.75% Senior Notes due February 15, 2014 (2) — 175 6.125% Senior Notes due May 15, 2016 175 175 5.50% Senior Notes due February 15, 2020 250 250 4.65% Senior Notes due February 15, 2022 300 300 3.45% Senior Notes due January 15, 2023 350 350 4.25% Senior Notes due April 1, 2024 500 — 6.85% Senior Notes due February 15, 2040 250 250 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.30% Senior Notes due April 1, 2044 700 — 5.35% Senior Notes due May 15, 2045 800 — Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015 (3) 35 35 Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018 150 200 Unamortized premiums, discounts and fair value adjustments, net 100 118 4,260 2,503 Sunoco LP Debt Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019 683 — 683 — Regency Debt 6.875% Senior Notes due December 1, 2018 — 600 5.75% Senior Notes due September 1, 2020 400 400 6.5% Senior Notes due July 15, 2021 500 500 5.875% Senior Notes due March 1, 2022 900 — 5.5% Senior Notes due April 15, 2023 700 700 4.5% Senior Notes due November 1, 2023 600 600 8.375% Senior Notes due June 1, 2020 390 — 6.5% Senior Notes due May 15, 2021 400 — 8.375% Senior Notes due June 1, 2019 499 — 5.0% Senior Notes due October 1, 2022 700 — Regency $2.0 billion Revolving Credit Facility due November 25, 2019 1,504 510 Unamortized premiums, discounts and fair value adjustments, net 48 — 6,641 3,310 Other 223 228 25,981 20,398 Less: current maturities 1,008 637 $ 24,973 $ 19,761 (1) In connection with the Panhandle Merger, Southern Union’s debt obligations were assumed by Panhandle. (2) Sunoco Logistics’ 8.75% senior notes due February 15, 2014 were classified as long-term debt as Sunoco Logistics repaid these notes in February 2014 with borrowings under its $1.50 billion credit facility due November 2018. (3) The Sunoco Logistics $35 million credit facility outstanding amounts were classified as long-term debt as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $280 million in unamortized net premiums and fair value adjustments: 2015 $ 1,050 2016 314 2017 1,228 2018 1,155 2019 4,262 Thereafter 17,692 Total $ 25,701 ETP as Co-Obligor of Sunoco, Inc. Debt In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $715 million as of December 31, 2014 . ETP Senior Notes The ETP senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually. The ETP senior notes are unsecured obligations of the Partnership and the obligation of the Partnership to repay the ETP senior notes is not guaranteed by any of the Partnership’s subsidiaries. As a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries. In June 2015, ETP issued $650 million aggregate principal amount of 2.50% senior notes due June 2018, $350 million aggregate principal amount of 4.15% senior notes due October 2020, $1.0 billion aggregate principal amount of 4.75% senior notes due January 2026 and $1.0 billion aggregate principal amount of 6.125% senior notes due December 2045. ETP used the net proceeds of $2.98 billion from the offering to pay 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 pay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes. Transwestern Senior Notes The Transwestern notes are payable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually. Panhandle Junior Subordinated Notes The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175% . The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.26% at December 31, 2014 . Sunoco LP Senior Notes In April 2015, Sunoco LP issued $800 million aggregate principal amount of 6.375% senior notes due April 2023. The net proceeds from the offering were used to fund the cash portion of the dropdown of Sunoco, LLC interests and to repay outstanding balances under the Sunoco LP revolving credit facility. In July 2015, Sunoco LP issued $600 million aggregate principal amount of 5.5% senior notes due August 2020. The net proceeds from the offering were used to fund a portion of the cash consideration for Sunoco LP’s acquisition of Susser. Sunoco Logistics Senior Notes Offerings In April 2014, Sunoco Logistics issued $300 million aggregate principal amount of 4.25% senior notes due April 2024 and $700 million aggregate principal amount of 5.30% senior notes due April 2044. In November 2014, Sunoco Logistics issued $200 million aggregate principal amount of 4.25% senior notes due April 2024 and $800 million aggregate principal amount of 5.35% senior notes due May 2045. Sunoco Logistics used the net proceeds from the offerings to pay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes. Regency Senior Notes The Regency senior notes are unsecured obligations of Regency and the obligation of Regency to repay the Regency senior notes is not guaranteed by us or any of Regency’s subsidiaries. The Regency senior notes effectively rank junior to all indebtedness and other liabilities of Regency’s existing and future subsidiaries. Interest is payable semi-annually. In February 2014, Regency issued $900 million aggregate principal amount of 5.875% senior notes due March 1, 2022. In March 2014, as part of the PVR Acquisition, Regency assumed the outstanding senior notes of PVR with an aggregate notional amount of $1.2 billion . The PVR senior notes consisted of $300 million principal amount of 8.25% senior notes due April 15, 2018, $400 million principal amount of 6.5% senior notes due May 15, 2021, and $473 million principal amount of 8.375% senior notes due June 1, 2020. In April 2014, Regency redeemed all of the $300 million principal amount of 8.25% senior notes due April 15, 2018 for $313 million in cash. In July 2014, Regency redeemed $83 million of the $473 million principal amount of 8.375% senior notes due June 1, 2020 for $91 million , including $8 million of accrued interest and redemption premium. In July 2014, Regency exchanged $499 million aggregate principal amount of 8.375% senior notes due 2019 of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% senior notes due 2019 issued by Regency and its wholly-owned subsidiary. In July 2014, Regency issued $700 million aggregate principal amount of 5.0% senior notes that mature on October 1, 2022. In December 2014, Regency redeemed all of the outstanding $600 million senior notes due 2018, for a total price of $621 million . On June 1, 2015, Regency redeemed all of the outstanding $499 million aggregate principal amount of its 8.375% senior notes due June 2019. The Regency senior notes were registered under the Securities Act of 1933 (as amended). Regency may redeem some or all of the Regency senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the Regency senior notes. The balance is payable upon maturity and interest is payable semi-annually. The senior notes issued by Regency are fully and unconditionally guaranteed, on a joint and several basis, by all of Regency’s consolidated subsidiaries, except for ELG and its wholly-owned subsidiaries, Aqua – PVR and ORS. As a result, excluding ELG, Aqua – PVR and ORS, the Regency senior notes effectively rank junior to any future indebtedness of Regency’s or its subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the Regency senior notes effectively rank junior to all indebtedness and other liabilities of Regency’s existing and future subsidiaries. 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 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. Credit Facilities ETP Credit Facility The ETP Credit Facility allows for borrowings of up to $2.5 billion and expires in October 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt. We use the ETP Credit Facility to provide temporary financing for our growth projects, as well as for general partnership purposes. In February 2015, ETP amended its revolving credit facility to increase the capacity to $3.75 billion . As of December 31, 2014 , the ETP Credit Facility had $570 million outstanding, and the amount available for future borrowings was $1.81 billion after taking into account letters of credit of $121 million . The weighted average interest rate on the total amount outstanding as of December 31, 2014 was 1.66% . Sunoco Logistics Credit Facilities Sunoco Logistics maintains a $1.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in November 2018. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions. The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2014 , the Sunoco Logistics Credit Facility had $150 million of outstanding borrowings. West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, maintains a $35 million revolving credit facility which expires in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. At December 31, 2014 , this credit facility had $35 million of outstanding borrowings. In March 2015, Sunoco Logistics amended and restated its 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, which matures in March 2020. Sunoco LP Credit Facility In September 2014, Sunoco LP entered into a $1.25 billion revolving credit agreement (the “Sunoco LP Credit Facility”), which matures in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million . As of December 31, 2014 , the Sunoco LP Credit Facility had $683 million of outstanding borrowings. In April 2015, Sunoco LP amended the Sunoco LP Credit Facility to allow for borrowings of up to $1.5 billion. Regency Credit Facility The Regency Credit Facility had aggregate revolving commitments of $2.0 billion , with a $500 million incremental facility. The maturity date of the Regency Credit Facility was November 25, 2019. The outstanding balance of revolving loans under the Regency Credit Facility bore interest at LIBOR plus a margin or an alternate base rate. The alternate base rate used to calculate interest on base rate loans was calculated using the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.00% . The applicable margin ranged from 0.625% to 1.50% for base rate loans and 1.625% to 2.50% for Eurodollar loans. Regency paid (i) a commitment fee ranging between 0.30% and 0.45% per annum for the unused portion of the revolving loan commitments; (ii) a participation fee for each revolving lender participating in letters of credit ranging between 1.625% and 2.50% per annum of the average daily amount of such lender’s letter of credit exposure and; (iii) a fronting fee to the issuing bank of letters of credit equal to 0.20% per annum of the average daily amount of its letter of credit exposure. The Regency Credit Facility allowed for investments in its joint ventures. As of December 31, 2014 , Regency had a balance outstanding of $1.50 billion under the Regency Credit Facility in revolving credit loans and approximately $23 million in letters of credit. The total amount available under the Regency Credit Facility, as of December 31, 2014 , which is reduced by any letters of credit, was approximately $473 million . The weighted average interest rate on the total amount outstanding as of December 31, 2014 was 2.17% . On April 30, 2015, in connection with the Regency Merger, the Regency Credit Facility was paid off in full and terminated. Covenants Related to Our Credit Agreements Covenants Related to ETP The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things: • incur indebtedness; • grant liens; • enter into mergers; • dispose of assets; • make certain investments; • make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement); • engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; • engage in transactions with affiliates; and • enter into restrictive agreements. The credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility. The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio. Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions. Covenants Related to Panhandle Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants. Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries. In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt. Covenants Related to Sunoco Logistics Sunoco Logistics’ $1.50 billion credit facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants related to the operation and conduct of the business of Sunoco Logistics and its subsidiaries. The credit facility also limits Sunoco Logistics, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1 , which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total consolidated debt, excluding net unamortized fair value adjustments, to consolidated Adjusted EBITDA was 3.7 to 1 at December 31, 2014 , as calculated in accordance with the credit agreements. The West Texas Gulf Pipeline Company’s $35 million credit facility limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio of 1.00 to 1 . In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1 . West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 1.67 to 1 and 0.85 to 1 , respectively, at December 31, 2014 . Covenants Related to Sunoco LP The Sunoco LP Credit Facility requires Sunoco LP to maintain a leverage ratio of not more than 5.50 to 1 . The maximum leverage ratio is subject to upwards adjustment of not more than 6.00 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in an acquisition of assets, equity interests, operating lines or divisions by Sunoco LP, a subsidiary, an unrestricted subsidiary or a joint venture for a purchase price of not less than $50 million . Indebtedness under the Sunoco LP Credit Facility is secured by a security interest in, among other things, all of the Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing the Sunoco LP Credit Facility will be released. Covenants Related to Regency The Regency senior notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries, to: • incur additional indebtedness; • pay distributions on, or repurchase or redeem equity interests; • make certain investments; • incur liens; • enter into certain types of transactions with affiliates; and • sell assets, consolidate or merge with or into other companies. If the Regency senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to these covenants except that the lien covenant will continue to be applicable. ETP provided a guarantee with respect to the outstanding Regency senior notes upon the closing of the Regency Merger. The Regency Credit Facility contained the following financial covenants: • Regency’s consolidated EBITDA ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.00 to 1 . • Regency’s consolidated EBITDA to consolidated interest expense, as defined in the credit agreement governing the Regency Credit Facility, must be greater than 2.50 to 1 . • Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3.25 to 1 . The Regency Credit Facility also contained various covenants that limit, among other things, the ability of Regency and RGS to: • incur indebtedness; • grant liens; • enter into sale and leaseback transactions; • make certain investments, loans and advances; • dissolve or enter into a merger or consolidation; • enter into asset sales or make acquisitions; • enter into transactions with affiliates; • prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility); • issue capital stock or create subsidiaries; or • engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof. Regency Credit Facility was paid off and terminated by ETP in connection with the Regency Merger. Compliance with our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2014 . |
Series A Preferred Units (Notes
Series A Preferred Units (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Temporary Equity Disclosure [Abstract] | |
Preferred Units [Text Block] | SERIES A PREFERRED UNITS: In connection with the closing of the Regency Merger, 1.9 million of Regency’s outstanding series A preferred units were converted into corresponding newly issued ETP Series A Preferred Units (the “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 . The Preferred Units were convertible to approximately 0.9 million ETP common units as of June 30, 2015. |
Redeemable Noncontrolling Inter
Redeemable Noncontrolling Interest (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Statement of Financial Position [Abstract] | |
Noncontrolling Interest Disclosure [Text Block] | REDEEMABLE NONCONTROLLING INTERESTS: The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheet as of December 31, 2014 . |
Equity (Notes)
Equity (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Equity [Abstract] | |
EQUITY | EQUITY: Limited Partner interests are represented by Common, Class E Units, Class G Units and Class H Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. As of December 31, 2014 , there were issued and outstanding 355.5 million Common Units representing an aggregate 99.3% Limited Partner interest in us. A total of 8.9 million Class E Units and 90.7 million Class G Units are outstanding and are reported as treasury units, which units are entitled to receive distributions in accordance with their terms. A total of 50.2 million Class H Units are also outstanding representing Limited Partner interests owned by ETE Holdings (see “Class H Units” below). No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance. IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs. 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. Common Units The change in Common Units was as follows: Years Ended December 31, 2014 2013 2012 Number of Common Units, beginning of period 333.8 301.5 225.5 Common Units issued in connection with the Susser Merger (see Note 3) 15.8 — — Common Units redeemed in connection with the Lake Charles LNG Transaction (see Note 3) (18.7 ) — — Common Units issued in connection with public offerings — 13.8 15.5 Common Units issued in connection with certain acquisitions — 49.5 57.4 Common Units redeemed for Class H Units — (50.2 ) — Common Units issued in connection with the Distribution Reinvestment Plan 2.8 2.3 1.0 Common Units issued in connection with Equity Distribution Agreements 21.4 16.9 1.6 Repurchases of Common Units in open-market transactions — (0.4 ) — Issuance of Common Units under equity incentive plans 0.4 0.4 0.5 Number of Common Units, end of period 355.5 333.8 301.5 Our Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.” Public Offerings The following table summarizes our public offerings of Common Units during the periods presented, all of which have been registered under the Securities Act of 1933 (as amended): Date Number of Common Units Price per Unit Net Proceeds July 2012 15.5 $ 44.57 $ 671 April 2013 13.8 48.05 657 Proceeds from the offerings listed above were used to repay amounts outstanding under the ETP Credit Facility and/or to fund capital expenditures and capital contributions to joint ventures, and for general partnership purposes. Equity Distribution Program From time to time, we have sold Common Units through an equity distribution agreement. Such sales of Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement. In January 2013 and May 2013, we entered into equity distribution agreements pursuant to which we may sell from time to time Common Units having aggregate offering prices of up to $200 million and $800 million , respectively. During the year ended December 31, 2014 , we issued approximately 2.7 million units for $144 million , net of commissions of $2 million . No amounts of our Common Units remain available to be issued under our January 2013 and May 2013 equity distribution agreements. In May 2014 and November 2014, we entered into equity distribution agreements pursuant to which we may sell from time to time Common Units having aggregate offering prices of up to $1.0 billion and $1.50 billion , respectively. During the year ended December 31, 2014 , we issued approximately 18.8 million units for $1.08 billion , net of commissions of $11 million . As of December 31, 2014 , approximately $1.41 billion of our Common Units remained available to be issued under our currently effective equity distribution agreements. During the six months ended June 30, 2015 , the Partnership received proceeds of $569 million , net of commissions of $6 million , from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes. As of June 30, 2015 , $832 million of the Partnership’s common units remained available to be issued under an equity distribution agreement. Equity Incentive Plan Activity As discussed in Note 10 , we issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations. Distribution Reinvestment Program Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. During the years ended December 31, 2014 , 2013 and 2012 , aggregate distributions of approximately $155 million , $109 million , and $43 million , respectively, were reinvested under the DRIP resulting in the issuance in aggregate of approximately 6.1 million Common Units. As of December 31, 2014 , a total of 7.3 million Common Units remain available to be issued under the existing registration statement. During the six months ended June 30, 2015 , distributions of $155 million were reinvested under the Distribution Reinvestment Plan resulting in the issuance of 2.8 million common units. As of June 30, 2015 , a total of 4.5 million common units remain available to be issued under the existing registration statement in connection with the Distribution Reinvestment Plan. Class E Units The Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to Unitholders other than the holders of Class E Units in proportion to their respective interests. The Class E Units are treated as treasury units for accounting purposes because they are owned by a subsidiary of ETP Holdco, Heritage Holdings, Inc. Although no plans are currently in place, management may evaluate whether to retire some or all of the Class E Units at a future date. All of the 8.9 million Class E Units outstanding are held by a subsidiary and are reported as treasury units. Class G Units In conjunction with the Sunoco Merger, we amended our partnership agreement to create Class F Units. The number of Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million , which included 40 million Class F Units issued in exchange for cash contributed by Sunoco, Inc. to us immediately prior to or concurrent with the closing of the Sunoco Merger. The Class F Units generally did not have any voting rights. The Class F Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class F Unit per year. In April 2013, all of the outstanding Class F Units were exchanged for Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in the consolidated financial statements. Class H Units and Class I Units Currently Outstanding Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. Bakken Transaction In March 2015, ETE transferred 30.8 million Partnership common units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics. 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. In connection with the transaction, ETP also issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ending March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Sales of Common Units by Subsidiaries With respect to our investments in Sunoco Logistics and Sunoco LP, we account for the difference between the carrying amount of our investment in and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions. As a result of Sunoco Logistics’ issuances of commo n units during the year ended December 31, 2014 , we recognized increases in partners’ capital of $113 million . As a result of Sunoco LP’s issuances of commo n units during the year ended December 31, 2014 , we recognized increases in partners’ capital of $62 million . 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 year ended ended December 31, 2014 , Sunoco Logistics received proceeds of $477 million , net of commissions of $5 million , from the issuance of 10.3 million common units pursuant to the equity distribution agreement, which were used for general partnership purposes. Additionally, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million in September 2014. The net proceeds from this offering were used to repay outstanding borrowings under the $1.50 billion Sunoco Logistics Credit Facility and for general partnership purposes. During the six months ended June 30, 2015 , Sunoco Logistics received proceeds of $385 million , net of commissions of $4 million , from the issuance of common units pursuant to the equity distribution. The proceeds 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. Sales of Common Units by Sunoco LP In October 2014 and November 2014, Sunoco LP issued an aggregate total of 9.1 million common units in an underwritten public offering. Aggregate net proceeds of $405 million from the offering were used to repay amounts outstanding under the $1.25 billion Sunoco LP Credit Facility and for general partnership purposes. In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million . The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility. Quarterly Distributions of Available Cash The Partnership Agreement requires that we distribute all of our Available Cash to our Unitholders and our General Partner within forty-five days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any of our fiscal quarters, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partner in its sole discretion to provide for the proper conduct of our business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in our Partnership Agreement. Our distributions of Available Cash from operating surplus, excluding incentive distributions, to our General Partner and Limited Partner interests are based on their respective interests as of the distribution record date. Incentive distributions allocated to our General Partner are determined based on the amount by which quarterly distribution to common Unitholders exceed certain specified target levels, as set forth in our Partnership Agreement. Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2011 February 7, 2012 February 14, 2012 $ 0.8938 March 31, 2012 May 4, 2012 May 15, 2012 0.8938 June 30, 2012 August 6, 2012 August 14, 2012 0.8938 September 30, 2012 November 6, 2012 November 14, 2012 0.8938 December 31, 2012 February 7, 2013 February 14, 2013 0.8938 March 31, 2013 May 6, 2013 May 15, 2013 0.8938 June 30, 2013 August 5, 2013 August 14, 2013 0.8938 September 30, 2013 November 4, 2013 November 14, 2013 0.9050 December 31, 2013 February 7, 2014 February 14, 2014 0.9200 March 31, 2014 May 5, 2014 May 15, 2014 0.9350 June 30, 2014 August 4, 2014 August 14, 2014 0.9550 September 30, 2014 November 3, 2014 November 14, 2014 0.9750 December 31, 2014 February 6, 2015 February 13, 2015 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units. The relinquishments subsequent to the Regency Merger were as follows: Total Year 2015 (for quarters ending subsequent to the Regency Merger on April 30, 2015) $ 56 2016 137 2017 128 2018 105 2019 95 Sunoco Logistics Quarterly Distributions of Available Cash Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2012 February 8, 2013 February 14, 2013 $ 0.2725 March 31, 2013 May 9, 2013 May 15, 2013 0.2863 June 30, 2013 August 8, 2013 August 14, 2013 0.3000 September 30, 2013 November 8, 2013 November 14, 2013 0.3150 December 31, 2013 February 10, 2014 February 14, 2014 0.3312 March 31, 2014 May 9, 2014 May 15, 2014 0.3475 June 30, 2014 August 8, 2014 August 14, 2014 0.3650 September 30, 2014 November 7, 2014 November 14, 2014 0.3825 December 31, 2014 February 9, 2015 February 13, 2015 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380 Sunoco Logistics Unit Split On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis. Sunoco LP Quarterly Distributions of Available Cash Distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014 were as follows: Quarter Ended Record Date Payment Date Rate September 30, 2014 November 18, 2014 November 28, 2014 $ 0.5457 December 31, 2014 February 17, 2015 February 27, 2015 0.6000 March 31, 2015 May 19, 2015 May 29, 2015 0.6450 June 30, 2015 August 18, 2015 August 28, 2015 0.6934 Predecessor Equity Issuances The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented: Date Number of Regency Common Units Price per Regency Unit Net Proceeds March 2012 12.7 $ 24.47 $ 297 Proceeds were used to repay amounts outstanding under the Regency Credit Facility and/or fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes. Regency issued 4.0 million , 140.4 million and 8.2 million Regency Common Units in connection with the Hoover, PVR and Eagle Rock Midstream acquisitions, respectively. In June 2014, Regency sold 14.4 million Regency Common Units to a wholly-owned subsidiary of ETE for approximately $400 million . Proceeds from the issuance were used to pay down borrowings on the Regency Credit Facility, to redeem certain Regency senior notes and for general partnership purposes. In July 2014, Regency sold an additional 16.5 million Regency Common Units to a wholly-owned subsidiary of ETE in connection with the Eagle Rock Midstream Acquisition for approximately $400 million . Proceeds from the issuance were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition. Regency’s Equity Distribution Program From time to time, Regency sold Regency Common Units through an equity distribution agreement. Such sales of Regency Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement. In June 2012, Regency entered into an equity distribution agreement with Citigroup Global Markets Inc. under which Regency may offer and sell Regency Common Units, representing limited partner interests, having an aggregate offering price of up to $200 million from time to time through Citi, as sales agent for Regency. For the years ended December 31, 2014 and 2013, Regency received net proceeds of $34 million and $149 million , respectively, from Regency Common Units issued pursuant to this equity distribution agreement. No amounts remain available to be issued under this agreement and it is no longer effective. In May 2014, Regency entered into an equity distribution agreement with a group of banks and investment companies under which Regency may offer and sell Regency Common Units, representing limited partner interests, for an aggregate offering price of up to $400 million , from time to time through this group of institutions, as sales agent for Regency. For the year ended December 31, 2014, Regency received net proceeds of $395 million from Regency Common Units issued pursuant to this equity distribution agreement. No amounts remain available to be issued under this agreement and it is no longer effective. In January 2015, Regency entered into an equity distribution agreement with a group of banks and investment companies (the “Managers”) under which Regency may offer and sell Regency Common Units for an aggregate offering price of up to $1 billion , from time to time through the Managers, as sales agent for Regency. Regency used the net proceeds from the sale of Regency Common Units for general partnership purposes. The equity distribution agreement was terminated as a result of the Regency Merger. Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: December 31, 2014 2013 Available-for-sale securities $ 3 $ 2 Foreign currency translation adjustment (3 ) (1 ) Net loss on commodity related hedges (1 ) (4 ) Actuarial gain (loss) related to pensions and other postretirement benefits (57 ) 56 Investments in unconsolidated affiliates, net 2 8 Total AOCI, net of tax $ (56 ) $ 61 The tables below set forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented: December 31, 2014 2013 Available-for-sale securities $ (1 ) $ (1 ) Foreign currency translation adjustment 2 1 Actuarial gain relating to pension and other postretirement benefits (37 ) (39 ) Total $ (36 ) $ (39 ) |
Unit-Based Compensation Plans (
Unit-Based Compensation Plans (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Deferred Compensation Arrangements [Abstract] | |
UNIT-BASED COMPENSATION PLANS | UNIT-BASED COMPENSATION PLANS: ETP Unit-Based Compensation Plan We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2014 , an aggregate total of 5.4 million ETP Common Units remain available to be awarded under our equity incentive plans. Restricted Units We have granted restricted unit awards to employees that vest over a specified time period, typically a five -year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five -year service vesting requirement. The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2013 3.2 $ 49.65 Awards granted 1.0 60.85 Awards vested (0.5 ) 48.12 Awards forfeited (0.1 ) 32.36 Unvested awards as of December 31, 2014 3.6 53.83 During the years ended December 31, 2014, 2013 and 2012 , the weighted average grant-date fair value per unit award granted was $60.85 , $50.54 and $43.93 , respectively. The total fair value of awards vested was $26 million , $29 million and $29 million , respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2014 , a total of 3.6 million unit awards remain unvested, for which ETP expects to recognize a total of $128 million in compensation expense over a weighted average period of 2.0 years . Cash Restricted Units. The Partnership has also granted cash restricted units, which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. As of December 31, 2014 , a total of 0.4 million unvested cash restricted units were outstanding. Based on the trading price of ETP Common Units at December 31, 2014 , the Partnership expects to recognize $24 million of unit-based compensation expense related to non-vested cash restricted units over a period of 1.8 years . Sunoco Logistics Unit-Based Compensation Plan Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco Logistics covering an additional 0.7 million Sunoco Logistics common units. As of December 31, 2014 , a total of 1.5 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $33 million of expense over a weighted average period of 2.9 years . Regency Unit-Based Compensation Plans Regency had the following awards outstanding as of December 31, 2014 : • 107,650 Regency Common Unit options, all of which are exercisable, with a weighted average exercise price of $22.68 per unit option; and • 2,167,719 Regency Phantom Units, with a weighted average grant date fair value of $24.31 per Phantom Unit. Regency began granting cash restricted units in 2014. These awards are service condition (time-based) grants which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one Regency Common Unit upon vesting. Regency had 379,328 cash restricted units outstanding at December 31, 2014 . All of Regency’s outstanding phantom units and cash restricted units were vested or converted to ETP restricted units and ETP cash restricted units, respectively, in connection with the Regency Merger. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | INCOME TAXES: As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows: Years Ended December 31, 2014 2013 2012 Current expense (benefit): Federal $ 321 $ 51 $ (3 ) State 86 (2 ) 4 Total 407 49 1 Deferred expense (benefit): Federal (50 ) (6 ) 45 State 1 54 17 Total (49 ) 48 62 Total income tax expense from continuing operations $ 358 $ 97 $ 63 Historically, our effective rate differed from the statutory rate primarily due to Partnership earnings that are not subject to U.S. federal and most state income taxes at the Partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3 ) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2014 and 2013 is as follows: December 31, 2014 December 31, 2013 Corporate Subsidiaries (1) Partnership (2) Consolidated Corporate Subsidiaries (1) Partnership (2) Consolidated Income tax expense (benefit) at U.S. statutory rate of 35 percent $ 217 $ — $ 217 $ (166 ) $ — $ (166 ) Increase (reduction) in income taxes resulting from: Nondeductible goodwill — — — 241 — 241 Nondeductible goodwill included in the Lake Charles LNG Transaction 105 — 105 — — — State income taxes (net of federal income tax effects) 9 45 54 31 5 36 Premium on debt retirement (10 ) — (10 ) — — — Foreign (8 ) — (8 ) — — — Other — — — (13 ) (1 ) (14 ) Income tax from continuing operations $ 313 $ 45 $ 358 $ 93 $ 4 $ 97 (1) Includes ETP Holdco, Susser, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd., Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. ETP Holdco, which was formed via the Sunoco Merger and the ETP Holdco Transaction (see Note 3 ), includes Sunoco, Inc. and Panhandle. ETE held a 60% interest in ETP Holdco until April 30, 2013. Subsequent to the ETP Holdco Acquisition (see Note 3 ) on April 30, 2013, ETP owns 100% of ETP Holdco. (2) Includes ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes. Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2014 2013 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 116 $ 217 Pension and other postretirement benefits 47 57 Long term debt 53 108 Other 111 104 Total deferred income tax assets 327 486 Valuation allowance (84 ) (74 ) Net deferred income tax assets $ 243 $ 412 Deferred income tax liabilities: Properties, plants and equipment $ (1,506 ) $ (1,544 ) Inventory (153 ) (302 ) Investment in unconsolidated affiliates (2,528 ) (2,244 ) Trademarks (355 ) (180 ) Other (32 ) (45 ) Total deferred income tax liabilities (4,574 ) (4,315 ) Net deferred income tax liability (4,331 ) (3,903 ) Less: current portion of deferred income tax liabilities, net (85 ) (119 ) Accumulated deferred income taxes $ (4,246 ) $ (3,784 ) The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3 ) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows: December 31, 2014 2013 Net deferred income tax liability, beginning of year $ (3,903 ) $ (3,628 ) Susser acquisition (488 ) — SUGS Contribution to Regency — (115 ) Tax provision (including discontinued operations) 60 (111 ) Other — (49 ) Net deferred income tax liability $ (4,331 ) $ (3,903 ) ETP Holdco, Susser and other corporate subsidiaries have gross federal net operating loss carryforwards of $5 million , all of which will expire in 2032 and 2033 . Our corporate subsidiaries had less than $1 million of federal alternative minimum tax credits at December 31, 2014 . Our corporate subsidiaries have state net operating loss carryforward benefits of $111 million , net of federal tax, which expire between 2014 and 2033 . The valuation allowance of $84 million is applicable to the state net operating loss carryforward benefits applicable to Sunoco, Inc. pre-acquisition periods. The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2014 2013 2012 Balance at beginning of year $ 429 $ 27 $ 2 Additions attributable to acquisitions — — 28 Additions attributable to tax positions taken in the current year 20 — — Additions attributable to tax positions taken in prior years (1 ) 406 — Settlements (5 ) — — Lapse of statute (3 ) (4 ) (3 ) Balance at end of year $ 440 $ 429 $ 27 As of December 31, 2014 , we have $439 million ( $425 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $4 million ( $2 million , net of federal tax) within the next twelve months due to settlement of certain positions. Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 open statute years, Sunoco, Inc. has proposed to the IRS that these government incentive payments be excluded from federal taxable income. If Sunoco, Inc. is fully successful with its claims, it will receive tax refunds of approximately $372 million . However, due to the uncertainty surrounding the claims, a reserve of $372 million was established for the full amount of the claims. Due to the timing of the expected settlement of the claims and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 2014 . Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2014 , we recognized interest and penalties of less than $1 million . At December 31, 2014 , we have interest and penalties accrued of $6 million , net of tax. In general, ETP and its subsidiaries are no longer subject to examination by the IRS for the 2010 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007 and Southern Union and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2004. Sunoco, Inc. has been examined by the IRS for tax years through 2012. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments. As of December 31, 2014 , the IRS has proposed only one adjustment for the years under examination. On July 23, 2015, we reached a final settlement with the Internal Revenue Service (“IRS”) with regards to the IRS examination of Southern Union’s tax years 2004 through 2009. For the 2006 tax year, the IRS had challenged $545 million of the $690 million of deferred gain associated with a like kind exchange involving certain assets of Southern Union’s distribution operations and its gathering and processing operations. The terms of the settlement specify that our position with regards to the deferred gain on the like kind exchange was materially correct and as a result, we will receive refunds totaling approximately $6 million for the periods under examination. During the three months ended June 30, 2015, Sunoco, Inc. filed a petition for refund with the United States Court of Federal Claims in response to a notice of disallowance denying previously filed refund claims related to certain government incentive payments. Also, during the same period, Sunoco, Inc. filed amended state income tax returns in material jurisdictions based on the Federal claim. The state refund claim is $87 million ( $57 million after Federal taxes). Consistent with treatment of Federal claims, Sunoco, Inc. has established a reserve for the full amount of the increase due to the uncertain nature of the claims. ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations. |
Regulatory Matters, Commitments
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
Commitments Contingencies and Guarantees [Text Block] | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million , representing the amount of the judgment, plus interest, in a case tried in 2011. On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011. FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs. Contingent Residual Support Agreement – AmeriGas In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchases. PEPL Holdings Guarantee of Collection In connection with the SUGS Contribution, Regency issued $600 million of 4.50% senior notes due 2023 (the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023. In connection with the completion of the Panhandle Merger, in which PEPL Holdings was merged with and into Panhandle, the guarantee of collection for the Regency Debt was assumed by Panhandle. On April 30, 2015, in connection with the Regency Merger, ETP entered into various supplemental indentures pursuant to which ETP had agreed to fully and unconditionally guarantee all payment obligations of Regency for all of its outstanding senior notes. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released. 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 August 2015. 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 May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015. Commitments In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations. We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058 . The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: Years Ended December 31, 2014 2013 2012 Rental expense (1) $ 159 $ 151 $ 60 Less: Sublease rental income (26 ) (24 ) (4 ) Rental expense, net $ 133 $ 127 $ 56 (1) Includes contingent rentals totaling $24 million , $22 million and $6 million for the years ended December 31, 2014 , 2013 and 2012 , respectively. Future minimum lease commitments for such leases are: Years Ending December 31: 2015 $ 151 2016 129 2017 118 2018 108 2019 102 Thereafter 829 Future minimum lease commitments 1,437 Less: Sublease rental income (34 ) Net future minimum lease commitments $ 1,403 Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. Litigation and Contingencies We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. MTBE Litigation Sunoco, Inc., along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees. As of December 31, 2014 , Sunoco, Inc. is a defendant in five cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. 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. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability of Sunoco, Inc. in these matters. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position. Regency Merger Litigation Following the January 26, 2015 announcement of the definitive merger agreement with Regency, purported Regency unitholders filed lawsuits in state and federal courts in Dallas, Texas and Delaware state court asserting claims relating to the proposed transaction. On February 3, 2015, William Engel and Enno Seago, purported Regency unitholders, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 162nd Judicial District Court of Dallas County, Texas (the “Engel Lawsuit”). The lawsuit names as defendants the Regency General Partner, the members of the Regency General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, Regency. The Engel Lawsuit alleges that (1) the Regency General Partner’s directors breached duties to Regency and the Regency’s unitholders by employing a conflicted and unfair process and failing to maximize the merger consideration; (2) the Regency General Partner’s directors breached the implied covenant of good faith and fair dealing by engaging in a flawed merger process; and (3) the non-director defendants aided and abetted in these claimed breaches. The plaintiffs seek an injunction preventing the defendants from closing the proposed transaction or an order rescinding the transaction if it has already been completed. The plaintiffs also seek money damages and court costs, including attorney’s fees. On February 9, 2015, Stuart Yeager, a purported Regency unitholder, filed a class action petition on behalf of the Regency’s common unitholders and a derivative suit on behalf of Regency in the 134th Judicial District Court of Dallas County, Texas (the “Yeager Lawsuit”). The allegations, claims, and relief sought in the Yeager Lawsuit are nearly identical to those in the Engel Lawsuit. On February 10, 2015, Lucien Coggia a purported Regency unitholder, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 192nd Judicial District Court of Dallas County, Texas (the “Coggia Lawsuit”). The allegations, claims, and relief sought in the Coggia Lawsuit are nearly identical to those in the Engel Lawsuit. On February 3, 2015, Linda Blankman, a purported Regency unitholder, filed a class action complaint on behalf of the Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Blankman Lawsuit”). The allegations and claims in the Blankman Lawsuit are similar to those in the Engel Lawsuit. However, the Blankman Lawsuit does not allege any derivative claims and includes Regency as a defendant rather than a nominal party. The lawsuit also omits one of the Regency General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the Regency General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of Regency, failing to properly value Regency, and ignoring conflicts of interest. The plaintiff also asserts a claim against the non-director defendants for aiding and abetting the directors’ alleged breach of fiduciary duty. The Blankman Lawsuit seeks the same relief that the plaintiffs seek in the Engel Lawsuit. On February 6, 2015, Edwin Bazini, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Bazini Lawsuit”). The allegations, claims, and relief sought in the Bazini Lawsuit are nearly identical to those in the Blankman Lawsuit. On March 27, 2015, Plaintiff Bazini filed an amended complaint asserting additional claims under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934. On February 11, 2015, Mark Hinnau, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Hinnau Lawsuit”). The allegations, claims, and relief sought in the Hinnau Lawsuit are nearly identical to those in the Blankman Lawsuit. On February 11, 2015, Stephen Weaver, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Weaver Lawsuit”). The allegations, claims, and relief sought in the Weaver Lawsuit are nearly identical to those in the Blankman Lawsuit. On February 11, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Dieckman Lawsuit are similar to those in the Blankman Lawsuit, except that the Dieckman Lawsuit does not assert an aiding and abetting claim. On February 13, 2015, Irwin Berlin, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Berlin Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit. On March 13, 2015, the Court in the 95th Judicial District Court of Dallas County, Texas transferred and consolidated the Yeager and Coggia Lawsuits into the Engel Lawsuit and captioned the consolidated lawsuit as Engel v. Regency GP, LP, et al . (the “Consolidated State Lawsuit”). On March 30, 2015, Leonard Cooperman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Cooperman Lawsuit”). The allegations, claims, and relief sought in the Cooperman Lawsuit are similar to those in the Blankman Lawsuit. On March 31, 2015, the Court in United States District Court for the Northern District of Texas consolidated the Blankman, Bazini, Hinnau, Weaver, Dieckman, and Berlin Lawsuits into a consolidated lawsuit captioned Bazini v. Bradley, et al . (the “Consolidated Federal Lawsuit”). On April 1, 2015, plaintiffs in the Consolidated Federal Lawsuit filed an Emergency Motion to Expedite Discovery. On April 9, 2015, by order of the Court, the parties submitted a joint submission wherein defendants opposed plaintiffs’ request to expedite discovery. On April 17, 2015, the Court denied plaintiffs’ motion to expedite discovery. On June 10, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware (the “Dieckman DE Lawsuit”). The lawsuit alleges that the transaction did not comply with the Regency partnership agreement because the Conflicts Committee was not properly formed. Each of these 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. Litigation Relating to the PVR Merger Five putative class action lawsuits challenging the PVR Acquisition are currently pending. All of these cases name PVR, PVR GP and the current directors of PVR GP, as well as the Partnership and the General Partner (collectively, the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in the alleged breach of these fiduciary duties, and, as to the actions in federal court, that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in general, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) in the event the merger is consummated, rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly causes by the defendants to these actions, and, (iv) such further relief as the court deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P., et al. (Case No. 9015-VCL) in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. (Case No. 2013-10606) and Saul Srour v. PVR Partners, L.P., et al. (Case No. 2013-011015), each pending in the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-06829-HB); and Mark Hinnau v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-07496-HB), pending in the United States District Court for the Eastern District of Pennsylvania. On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, completion of certain confirmatory discovery, class certification and final approval by the Court of Common Pleas for Delaware County, Pennsylvania. If the Court approves the settlement, the Settled Lawsuits will be dismissed with prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits. The settlement will not affect any provisions of the merger agreement or the form or amount of consideration to be received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation. Eagle Rock Shareholder Litigation Three putative class action lawsuits challenging the Eagle Rock Midstream Acquisition are currently pending in federal district court in Houston, Texas. All cases name Eagle Rock and its current directors, as well as the Partnership and a subsidiary, as defendants. One of the lawsuits also names additional Eagle Rock entities as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock. The Plaintiffs in each case seek to rescind the transaction, claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. Plaintiffs also seek monetary damages and attorneys’ fees. Regency and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board. Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million , consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise has filed a notice of appeal. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed. Other Litigation and Contingencies We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2014 and 2013 , accruals of approximately $37 million and $46 million , respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period. The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. No amounts have been recorded in our December 31, 2014 or 2013 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. Air Quality Control SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three SUGS recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard. Compliance Orders from the New Mexico Environmental Department SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until March 2014 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses. Environmental Matters Our operations are subject to extensive federal, 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 December 31, 2014 , Sunoco, Inc. had been named as a PRP at approximately 51 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 |
Price risk management assets an
Price risk management assets and liabilties (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |
PRICE RISK MANAGEMENT ASSETS AND LIABILITIES | PRICE RISK MANAGEMENT ASSETS AND LIABILITIES: Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We 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 statement 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 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. Since the first quarter 2013, Sunoco Logistics has not designated 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 the 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. ETP’s Preferred Units (see Note 7 ) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and ETP’s call option. These embedded derivatives are accounted for using mark-to-market accounting. ETP does not expect the embedded derivatives to affect its cash flows. Regency Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Marketing & Trading . Regency conducts natural gas marketing and trading activities through its Logistics and Trading subsidiary. Regency engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. Regency enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales and realized (unrealized) gain (loss) from derivatives, as appropriate. Through its natural gas marketing activity, Regency has credit exposure to additional counterparties. Regency minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, Regency’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, Regency nets the open positions of each counterparty. The following table details the outstanding commodity-related derivatives related to ETP’s legacy operations and Regency’s operations: ETP Legacy Operations December 31, 2014 December 31, 2013 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (232,500 ) 2015 9,457,500 2014-2019 Basis Swaps IFERC/NYMEX (1) (13,907,500 ) 2015-2016 (487,500 ) 2014-2017 Swing Swaps — — 1,937,500 2014-2016 Options – Calls 5,000,000 2015 — — Power (Megawatt): Forwards 288,775 2015 351,050 2014 Futures (156,000 ) 2015 (772,476 ) 2014 Options – Puts (72,000 ) 2015 (52,800 ) 2014 Options – Calls 198,556 2015 103,200 2014 Crude (Bbls) – Futures — — 103,000 2014 (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX 57,500 2015 570,000 2014 Swing Swaps IFERC 46,150,000 2015 (9,690,000 ) 2014-2016 Fixed Swaps/Futures (8,779,000 ) 2015-2016 (8,195,000 ) 2014-2015 Forward Physical Contracts (9,116,777 ) 2015 5,668,559 2014-2015 Natural Gas Liquid (Bbls) – Forwards/Swaps (2,179,400 ) 2015 (1,133,600 ) 2014 Refined Products (Bbls) – Futures 13,745,755 2015 (280,000 ) 2014 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (39,287,500 ) 2015 (7,352,500 ) 2014 Fixed Swaps/Futures (39,287,500 ) 2015 (50,530,000 ) 2014 Hedged Item – Inventory 39,287,500 2015 50,530,000 2014 Cash Flow Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX — — (1,825,000 ) 2014 Fixed Swaps/Futures — — (12,775,000 ) 2014 Natural Gas Liquid (Bbls) – Forwards/Swaps — — (780,000 ) 2014 Crude (Bbls) – Futures — — (30,000 ) 2014 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. Regency Operations December 31, 2014 December 31, 2013 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Non-Trading) Natural Gas (MMBtu) — Fixed Swaps/Futures (25,525,000 ) 2015 (24,455,000 ) 2014-2015 Propane (Gallons) — Forwards/Swaps (29,148,000 ) 2015 (52,122,000 ) 2014-2015 NGLs (Barrels) — Forwards/Swaps (292,000 ) 2015 (438,000 ) 2014 WTI Crude Oil (Barrels) — Forwards/Swaps (1,252,000 ) 2015-2016 (521,000 ) 2014 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: Entity Term Type (1) Notional Amount Outstanding December 31, 2014 December 31, 2013 ETP July 2014 (2) Forward-starting to pay a fixed rate of 4.25% and receive a floating rate $ — $ 400 ETP July 2015 (2) Forward-starting to pay a fixed rate of 3.38% and receive a floating rate 200 — ETP July 2016 (3) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 200 — ETP July 2017 (4) Forward-starting to pay a fixed rate of 3.84% and receive a floating rate 300 — ETP July 2018 (4) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 — ETP July 2019 (4) Forward-starting to pay a fixed rate of 3.19% and receive a floating rate 300 — ETP July 2018 Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% — 600 ETP June 2021 Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% — 400 ETP February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% 200 400 Panhandle November 2021 Pay a fixed rate of 3.82% and receive a floating rate — 275 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have terms of 10 years with a mandatory termination date the same as the effective date. (3) Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date. (4) Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may at times require collateral under certain circumstances to mitigate credit risk as necessary. 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, municipalities, gas and electric utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. 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 December 31, 2014 December 31, 2013 December 31, 2014 December 31, 2013 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 43 $ 2 $ — $ (20 ) 43 2 — (20 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) $ 617 $ 227 $ (577 ) $ (209 ) Commodity derivatives 107 43 (23 ) (45 ) Interest rate derivatives 3 47 (155 ) (95 ) Embedded derivatives in Regency Preferred Units — — (16 ) (19 ) 727 317 (771 ) (368 ) Total derivatives $ 770 $ 319 $ (771 ) $ (388 ) The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2014 December 31, 2013 December 31, 2014 December 31, 2013 Derivatives in offsetting agreements: OTC contracts Price risk management assets (liabilities) $ 23 $ 42 $ (23 ) $ (38 ) Broker cleared derivative contracts Other current assets 674 264 (574 ) (318 ) 697 306 (597 ) (356 ) Offsetting agreements: Counterparty netting Price risk management assets (liabilities) (19 ) (36 ) 19 36 Payments on margin deposit Other current assets 5 (1 ) (22 ) 55 (14 ) (37 ) (3 ) 91 Net derivatives with offsetting agreements 683 269 (600 ) (265 ) Derivatives without offsetting agreements 87 50 (171 ) (123 ) Total derivatives $ 770 $ 319 $ (771 ) $ (388 ) 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) Years Ended December 31, 2014 2013 2012 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ (1 ) $ 8 Total $ — $ (1 ) $ 8 Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Years Ended December 31, 2014 2013 2012 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ (3 ) $ 4 $ 14 Total $ (3 ) $ 4 $ 14 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2014 2013 2012 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ (8 ) $ 8 $ 54 Total $ (8 ) $ 8 $ 54 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Years Ended December 31, 2014 2013 2012 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (6 ) $ (11 ) $ (7 ) Commodity derivatives – Non-trading Cost of products sold 199 (21 ) 26 Commodity contracts – Non-trading Deferred gas purchases — (3 ) (26 ) Interest rate derivatives Gains (losses) on interest rate derivatives (157 ) 53 (19 ) Embedded derivatives Other income 3 6 14 Total $ 39 $ 24 $ (12 ) |
Retirement Benefits (Notes)
Retirement Benefits (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
RETIREMENT BENEFITS | |
Pension and Other Postretirement Benefits Disclosure | RETIREMENT BENEFITS: Savings and Profit Sharing Plans We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $59 million , $47 million and $30 million to these 401(k) savings plans for the years ended December 31, 2014, 2013 and 2012 , respectively. Pension and Other Postretirement Benefit Plans Panhandle Panhandle offered postretirement health care and life insurance plans that were available to substantially all of its employees, pending the retiree meeting certain age and service requirements. Sunoco, Inc. Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan and anticipates approval for the distribution of assets from the plan, pending approval from the Pension Benefit Guaranty Corporation and the IRS, in the fourth quarter of 2015. Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations. Obligations and Funded Status Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2014 December 31, 2013 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 632 $ 61 $ 223 $ 1,117 $ 78 $ 296 Service cost — — — 3 — — Interest cost 28 3 5 33 2 6 Amendments — — 1 — — 2 Benefits paid, net (45 ) (9 ) (28 ) (99 ) (16 ) (26 ) Actuarial (gain) loss and other 130 10 2 (74 ) (3 ) (14 ) Settlements (27 ) — — (95 ) — — Dispositions — — (1 ) (253 ) — (41 ) Benefit obligation at end of period 718 65 202 632 61 223 Change in plan assets: Fair value of plan assets at beginning of period 600 — 284 906 — 312 Return on plan assets and other 70 — 6 43 — 17 Employer contributions — — 8 — — 8 Benefits paid, net (45 ) — (28 ) (99 ) — (26 ) Settlements (27 ) — — (95 ) — — Dispositions — — (5 ) (155 ) — (27 ) Fair value of plan assets at end of period 598 — 265 600 — 284 Amount underfunded (overfunded) at end of period $ 120 $ 65 $ (63 ) $ 32 $ 61 $ (61 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 90 $ — $ — $ 86 Current liabilities — (9 ) (2 ) — (9 ) (2 ) Non-current liabilities (120 ) (56 ) (25 ) (32 ) (52 ) (23 ) $ (120 ) $ (65 ) $ 63 $ (32 ) $ (61 ) $ 61 Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: Net actuarial gain $ 18 $ 7 $ (20 ) $ (86 ) $ (4 ) $ (25 ) Prior service cost — — 17 — — 18 $ 18 $ 7 $ (3 ) $ (86 ) $ (4 ) $ (7 ) The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2014 December 31, 2013 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 718 $ 65 N/A $ 632 61 N/A Accumulated benefit obligation 718 65 202 632 61 $ 223 Fair value of plan assets 598 — 265 600 — 284 Components of Net Periodic Benefit Cost December 31, 2014 December 31, 2013 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ — $ — $ 3 $ — Interest cost 31 5 35 6 Expected return on plan assets (40 ) (8 ) (54 ) (9 ) Prior service cost amortization — 1 — 1 Actuarial loss amortization (1 ) (1 ) 2 — Settlements (4 ) — (2 ) — (14 ) (3 ) (16 ) (2 ) Regulatory adjustment (1) — — 5 — Net periodic benefit cost $ (14 ) $ (3 ) $ (11 ) $ (2 ) (1) Southern Union, the predecessor of Panhandle, historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its distribution operations. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission. Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2014 December 31, 2013 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.62 % 2.24 % 4.65 % 2.33 % Rate of compensation increase N/A N/A N/A N/A The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2014 December 31, 2013 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 4.65 % 3.02 % 3.50 % 2.68 % Expected return on assets: Tax exempt accounts 7.50 % 7.00 % 7.50 % 6.95 % Taxable accounts N/A 4.50 % N/A 4.42 % Rate of compensation increase N/A N/A N/A N/A The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness. The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: December 31, 2014 2013 Health care cost trend rate 7.09 % 7.57 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.41 % 5.42 % Year that the rate reaches the ultimate trend rate 2018 2018 Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits. Plan Assets For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35% , fixed income of 65% to 75% and cash and cash equivalents of up to 10% . The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets. The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 25 $ 25 $ — $ — Mutual funds (1) 110 — 110 — Fixed income securities 463 — 463 — Total $ 598 $ 25 $ 573 $ — (1) Primarily comprised of approximately 100% equities as of December 31, 2014 . Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy Fair Value as of December 31, 2013 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 12 $ 12 $ — $ — Mutual funds (1) 368 — 281 87 Fixed income securities 220 — 220 — Total $ 600 $ 12 $ 501 $ 87 (1) Primarily comprised of approximately 41% equities, 45% fixed income securities, and 14% in other investments as of December 31, 2013 . The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 9 $ 9 $ — $ — Mutual funds (1) 131 131 — — Fixed income securities 125 — 125 — Total $ 265 $ 140 $ 125 $ — (1) Primarily comprised of approximately 56% equities, 38% fixed income securities and 6% cash as of December 31, 2014 . Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy Fair Value as of December 31, 2013 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 10 $ 10 $ — $ — Mutual funds (1) 130 112 18 — Fixed income securities 144 — 144 — Total $ 284 $ 122 $ 162 $ — (1) Primarily comprised of approximately 41% equities, 48% fixed income securities, 6% cash, and 5% in other investments as of December 31, 2013 . The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. See Note 2 for information related to the framework used to measure the fair value of its pension and other postretirement plan assets. Contributions We expect to contribute approximately $129 million to pension plans and approximately $10 million to other postretirement plans in 2015 . The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes. Benefit Payments Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Pension Benefits Years Funded Plans Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2015 $ 717 $ 9 $ 28 2016 — 8 26 2017 — 7 25 2018 — 7 23 2019 — 6 22 2020 – 2024 — 23 65 The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Panhandle does not expect to receive any Medicare Part D subsidies in any future periods. |
Related Party Transactions (Not
Related Party Transactions (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
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. The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. The following table summarizes the affiliate revenues on our consolidated statements of operations: Years Ended December 31, 2014 2013 2012 Affiliated revenues $ 965 $ 1,442 $ 188 The following table summarizes the related company balances on our consolidated balance sheets: December 31, 2014 2013 Accounts receivable from related companies: ETE $ 11 $ 18 Dakota Access Pipeline 68 — PES 6 7 FGT 9 29 ET Crude Oil 10 24 Lake Charles LNG 3 — Other 32 39 Total accounts receivable from related companies: $ 139 $ 117 Accounts payable to related companies: ETE $ — $ 10 FGT 2 8 Lake Charles LNG 2 — Other 21 7 Total accounts payable to related companies: $ 25 $ 25 |
Reportable Segments (Notes)
Reportable Segments (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
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. Previously, our reportable segments included a separate segment for NGL transportation and services, which has now been combined into our liquids transportation and services segment and includes our operations related to NGL and crude, except for the crude transportation operations that are included in Sunoco Logistics. The liquids transportation and services segment includes the Bakken crude project, for which capital expenditures had previously been reported in the “All other” segment. During the fourth quarter 2013, management realigned the composition of our reportable segments, and as a result, our natural gas marketing operations are now aggregated into the “all other” segment. These operations were previously reported in the midstream segment. Based on this change in our segment presentation, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation. 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, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership. The following tables present financial information by segment: Years Ended December 31, 2014 2013 2012 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,645 $ 2,242 $ 2,010 Intersegment revenues 212 210 181 2,857 2,452 2,191 Interstate transportation and storage: Revenues from external customers 1,057 1,270 1,109 Intersegment revenues 15 39 — 1,072 1,309 1,109 Midstream: Revenues from external customers 4,770 3,220 2,869 Intersegment revenues 2,053 1,056 208 6,823 4,276 3,077 Liquids transportation and services: Revenues from external customers 3,730 2,025 619 Intersegment revenues 181 101 31 3,911 2,126 650 Investment in Sunoco Logistics: Revenues from external customers 17,920 16,480 3,109 Intersegment revenues 168 159 80 18,088 16,639 3,189 Retail marketing: Revenues from external customers 22,484 21,004 5,926 Intersegment revenues 3 8 — 22,487 21,012 5,926 All other: Revenues from external customers 2,869 2,094 1,322 Intersegment revenues 462 503 440 3,331 2,597 1,762 Eliminations (3,094 ) (2,076 ) (940 ) Total revenues $ 55,475 $ 48,335 $ 16,964 Years Ended December 31, 2014 2013 2012 Cost of products sold: Intrastate transportation and storage $ 2,169 $ 1,737 $ 1,394 Midstream 4,893 3,130 2,120 Liquids transportation and services 3,166 1,654 361 Investment in Sunoco Logistics 17,110 15,574 2,885 Retail marketing 21,154 20,150 5,757 All other 2,975 2,337 1,511 Eliminations (3,078 ) (2,028 ) (940 ) Total cost of products sold $ 48,389 $ 42,554 $ 13,088 Years Ended December 31, 2014 2013 2012 Depreciation, depletion and amortization: Intrastate transportation and storage $ 125 $ 122 $ 122 Interstate transportation and storage 203 244 209 Midstream 569 335 277 Liquids transportation and services 113 91 53 Investment in Sunoco Logistics 296 265 63 Retail marketing 189 114 28 All other 174 125 106 Total depreciation and amortization $ 1,669 $ 1,296 $ 858 Years Ended December 31, 2014 2013 2012 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 27 $ 30 $ 33 Interstate transportation and storage 196 182 162 Midstream 10 1 (10 ) Liquids transportation and services (3 ) (2 ) 2 Investment in Sunoco Logistics 23 18 5 Retail marketing 2 2 1 All other 77 5 19 Total equity in earnings of unconsolidated affiliates $ 332 $ 236 $ 212 Years Ended December 31, 2014 2013 2012 Segment Adjusted EBITDA: Intrastate transportation and storage $ 559 $ 521 $ 667 Interstate transportation and storage 1,212 1,368 1,117 Midstream 1,349 766 613 Liquids transportation and services 591 350 209 Investment in Sunoco Logistics 971 871 219 Retail marketing 731 325 109 All other 297 203 205 Total Segment Adjusted EBITDA 5,710 4,404 3,139 Depreciation, depletion and amortization (1,669 ) (1,296 ) (858 ) Interest expense, net of interest capitalized (1,165 ) (1,013 ) (788 ) Gain on deconsolidation of Propane Business — — 1,057 Gain on sale of AmeriGas common units 177 87 — Goodwill impairment (370 ) (689 ) — Gains (losses) on interest rate derivatives (157 ) 44 (4 ) Non-cash unit-based compensation expense (68 ) (54 ) (47 ) Unrealized gains (losses) on commodity risk management activities 112 42 2 Inventory valuation adjustments (473 ) 3 (75 ) Loss on extinguishment of debt (25 ) (7 ) (124 ) Non-operating environmental remediation — (168 ) — Adjusted EBITDA related to discontinued operations (27 ) (76 ) (99 ) Adjusted EBITDA related to unconsolidated affiliates (748 ) (722 ) (646 ) Equity in earnings of unconsolidated affiliates 332 236 212 Other, net (36 ) 19 48 Income from continuing operations before income tax expense $ 1,593 $ 810 $ 1,817 December 31, 2014 2013 2012 Assets: Intrastate transportation and storage $ 4,984 $ 5,048 $ 5,340 Interstate transportation and storage 10,779 11,537 12,376 Midstream 15,562 7,847 7,189 Liquids transportation and services 4,568 4,321 3,742 Investment in Sunoco Logistics 13,619 11,650 10,291 Retail marketing 8,930 3,936 3,926 All other 4,232 5,561 5,530 Total assets $ 62,674 $ 49,900 $ 48,394 Years Ended December 31, 2014 2013 2012 Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis): Intrastate transportation and storage $ 169 $ 47 $ 37 Interstate transportation and storage 411 152 133 Midstream 1,298 1,114 1,633 Liquids transportation and services 427 448 1,306 Investment in Sunoco Logistics 2,510 1,018 139 Retail marketing 259 176 58 All other 420 372 227 Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs $ 5,494 $ 3,327 $ 3,533 December 31, 2014 2013 2012 Advances to and investments in unconsolidated affiliates: Intrastate transportation and storage $ 423 $ 443 $ 652 Interstate transportation and storage 2,649 2,588 2,723 Midstream 138 36 36 Liquids transportation and services 31 29 29 Investment in Sunoco Logistics 226 125 118 Retail marketing 19 22 21 All other 274 807 1,189 Total advances to and investments in unconsolidated affiliates $ 3,760 $ 4,050 $ 4,768 |
Quarterly Financial Data (Notes
Quarterly Financial Data (Notes) | 12 Months Ended |
Dec. 31, 2014 | |
Quarterly Financial Data [Abstract] | |
QUARTERLY FINANCIAL DATA (UNAUDITED) | QUARTERLY FINANCIAL DATA (UNAUDITED): Summarized unaudited quarterly financial data is presented below. The sum of net income per Limited Partner unit by quarter does not equal the net income per limited partner unit for the year due to the computation of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts. Quarters Ended March 31 June 30 September 30 December 31 Total Year 2014: Revenues $ 13,027 $ 14,088 $ 14,933 $ 13,427 $ 55,475 Gross profit 1,585 1,737 1,919 1,845 7,086 Operating income 706 769 809 159 2,443 Net income 483 548 513 (245 ) 1,299 Common Unitholders’ interest in net income (loss) 253 295 148 (90 ) 606 Basic net income (loss) per Common Unit $ 0.76 $ 0.92 $ 0.44 $ (0.28 ) $ 1.77 Diluted net income (loss) per Common Unit $ 0.76 $ 0.92 $ 0.44 $ (0.28 ) $ 1.77 Quarters Ended March 31 June 30 September 30 December 31 Total Year 2013: Revenues $ 11,179 $ 12,063 $ 12,486 $ 12,607 $ 48,335 Gross profit 1,372 1,497 1,422 1,490 5,781 Operating income (loss) 541 671 545 (138 ) 1,619 Net income (loss) 402 411 415 (482 ) 746 Common Unitholders’ interest in net income (loss) 194 165 209 (666 ) (98 ) Basic net income (loss) per Common Unit $ 0.63 $ 0.53 $ 0.55 $ (1.90 ) $ (0.18 ) Diluted net income (loss) per Common Unit $ 0.63 $ 0.53 $ 0.55 $ (1.90 ) $ (0.18 ) The three months ended December 31, 2014 reflected the unfavorable impacts of $456 million related to non-cash inventory valuation adjustments primarily in our investment in Sunoco Logistics and retail marketing segments and Regency’s recognition of a goodwill impairment of $ 370 million . The three months ended December 31, 2013 reflected ETP’s recognition of a goodwill impairment of $689 million . For the three months ended December 31, 2014 and 2013 , distributions paid for the period exceeded net income attributable to partners by $544 million and $1.12 billion , respectively. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period. |
Estimates, Significant Accoun25
Estimates, Significant Accounting Policies and Balance Sheet Detials (Policy) | 12 Months Ended |
Dec. 31, 2014 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Pronouncements In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810) (“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. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies. In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations. Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed. |
Revenue Recognition | Revenue Recognition Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues. Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer. In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations. Our retail marketing segment sells gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease with the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured. Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas, NGL, condensate and salt water gathering, processing and transportation, (iii) contract compression and treating services and (iv) coal royalties. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression and contract treating services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas and NGLs at a price approximating the index price to third parties. Regency generally reports revenue gross in the consolidated statements of operations when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification. Regency recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. Regency does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. Regency records any differences between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most lessees must make minimum monthly or annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned. |
Regulatory Accounting - Regulatory Assets and Liabilities | Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs. |
Cash, Cash Equivalents and Supplemental Cash Flow Information | Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. The net change in operating assets and liabilities (net of acquisitions) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2014 2013 2012 Accounts receivable $ 600 $ (557 ) $ 267 Accounts receivable from related companies (22 ) 26 (12 ) Inventories 51 (254 ) (258 ) Exchanges receivable 18 (8 ) 14 Other current assets 132 (58 ) 574 Other non-current assets, net (6 ) (45 ) (30 ) Accounts payable (851 ) 542 (990 ) Accounts payable to related companies 3 (143 ) 101 Exchanges payable (99 ) 128 — Accrued and other current liabilities (92 ) 211 (169 ) Other non-current liabilities (73 ) 147 25 Price risk management assets and liabilities, net 19 (147 ) (15 ) Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (320 ) $ (158 ) $ (493 ) Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2014 2013 2012 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 643 $ 226 $ 420 Net gains from subsidiary common unit issuances $ 175 $ — $ — AmeriGas limited partner interest received in exchange for contribution of Propane Business $ — $ — $ 1,123 NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the Susser Merger (see Note 3) $ 908 $ — $ — Redemption of Common Units in connection with the Lake Charles LNG Transaction (see Note 3) $ 1,167 $ — $ — Issuance of Common Units in connection with the ETP Holdco Acquisition $ — $ 2,464 $ — Issuance of Class H Units $ — $ 1,514 $ — Long-term debt assumed and non-compete agreement notes payable issued in acquisitions $ 564 $ — $ 6,658 Issuance of Common Units in connection with other acquisitions $ — $ — $ 2,295 Predecessor equity issuance of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions $ 4,281 $ — $ — Long-term debt assumed in PVR Acquisition $ 1,887 $ — $ — Long-term debt exchanged in Eagle Rock Midstream Acquisition $ 499 $ — $ — SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,232 $ 1,049 $ 790 Cash paid for income taxes $ 344 $ 58 $ 23 |
Accounts Receivable | Accounts Receivable Our midstream, NGL and intrastate transportation and storage operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned for all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. Master setoff agreements are put in place with counterparties where appropriate to mitigate risk. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Based on that review, a letter of credit or other security may be required. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted. Our interstate transportation and storage operations have a concentration of customers in the electric and gas utility industries, municipalities, as well as natural gas producers. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral. Management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Our interstate transportation and storage operations establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectability. Our retail marketing segment extends credit to customers after a review of various credit indicators. Depending on the type of customer and its risk profile, security in the form of a cash deposit, letter of credit or mortgages may be required. Management records reserves for bad debt by computing a proportion of average write-off activity over the past five years in comparison to the outstanding balance in accounts receivable. This proportion is then applied to the accounts receivable balance at the end of the reporting period to calculate a current estimate of what is uncollectible. The allowance computation may then be adjusted to reflect input provided by the credit department and business line managers who may have specific knowledge of uncollectible items. The credit department and business line managers make the decision to write off an account, based on understanding of the potential collectability. We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets. |
Inventories | Inventories Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method. Inventories consisted of the following: December 31, 2014 2013 Natural gas and NGLs $ 392 $ 577 Crude oil 364 488 Refined products 392 543 Appliances, parts and fittings, and other 312 199 Total inventories $ 1,460 $ 1,807 During the year ended December 31, 2014 , the Partnership recorded write-downs of $473 million on its crude oil, refined products and NGL inventories as a result of a decline in the market price of these products. The write-down was calculated based upon current replacement costs. We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations. |
Exchanges | Exchanges Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms. |
Other Current Assets | Other Current Assets Other current assets consisted of the following: December 31, 2014 2013 Deposits paid to vendors $ 65 $ 49 Deferred income taxes 14 — Prepaid expenses and other 217 262 Total other current assets $ 296 $ 311 |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. We review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds. Components and useful lives of property, plant and equipment were as follows: December 31, 2014 2013 Land and improvements $ 1,307 $ 881 Buildings and improvements (1 to 45 years) 1,918 935 Pipelines and equipment (5 to 83 years) 27,164 21,038 Natural gas and NGL storage facilities (5 to 46 years) 1,215 1,083 Bulk storage, equipment and facilities (2 to 83 years) 2,583 1,933 Tanks and other equipment (5 to 40 years) 58 1,697 Retail equipment (2 to 99 years) 515 450 Vehicles (1 to 25 years) 203 156 Right of way (20 to 83 years) 2,445 2,183 Furniture and fixtures (2 to 25 years) 57 51 Linepack 119 118 Pad gas 44 52 Natural resources 454 — Other (1 to 30 years) 979 706 Construction work-in-process 4,343 2,166 43,404 33,449 Less – Accumulated depreciation (4,497 ) (3,113 ) Property, plant and equipment, net $ 38,907 $ 30,336 We recognized the following amounts of depreciation expense for the periods presented: Years Ended December 31, 2014 2013 2012 Depreciation expense $ 1,459 $ 1,202 $ 783 Capitalized interest, excluding AFUDC $ 101 $ 45 $ 99 |
Advances to and Investment in Affiliates | Advances to and Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. |
Goodwill | Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for subsidiaries in our intrastate transportation and storage and midstream segments and during the fourth quarter for subsidiaries in our interstate transportation and storage, liquids transportation and services and retail marketing segments and all others, including all of Regency’s reporting units. We recorded goodwill impairments for the periods presented in these consolidated financial statements. Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream Liquids Transportation and Services Investment in Sunoco Logistics Retail Marketing All Other Total Balance, December 31, 2012 $ 10 $ 1,884 $ 688 $ 432 $ 1,368 $ 1,272 $ 742 $ 6,396 Goodwill acquired — — — — — 156 — 156 Goodwill impairment — (689 ) — — — — — (689 ) Other — — (2 ) — (22 ) 17 — (7 ) Balance, December 31, 2013 10 1,195 686 432 1,346 1,445 742 5,856 Goodwill acquired — — 451 — 12 1,862 15 2,340 Goodwill disposed — (184 ) — — — — — (184 ) Goodwill impairment — — (370 ) — — — — (370 ) Balance, December 31, 2014 $ 10 $ 1,011 $ 767 $ 432 $ 1,358 $ 3,307 $ 757 $ 7,642 Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. We recorded a net increase in goodwill of $1.79 billion during the year ended December 31, 2014 primarily due to the Susser Merger and PVR Acquisition where we recorded goodwill of $1.73 billion and $370 million , respectively, offset by an impairment of $370 million , as discussed below. The additional goodwill recorded during the years ended December 31, 2014 and 2013 is not expected to be deductible for tax purposes. During the fourth quarter of 2014, a $370 million goodwill impairment was recorded related to Regency’s Permian Basin gathering and processing operations. The decline in estimated fair value of that reporting unit was primarily driven by the significant decline in commodity prices in the fourth quarter of 2014, and the resulting impact to future commodity prices as well as increases in future estimated operations and maintenance expenses. An assessment of these factors in the fourth quarter of 2014 led to a conclusion that the estimated fair value of Regency’s Permian reporting unit was less than its carrying amount. During the fourth quarter of 2013, we performed a goodwill impairment test on our Lake Charles LNG reporting unit. In accordance with GAAP, we performed step one of the goodwill impairment test and determined that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount primarily due to changes related to (i) the structure and capitalization of the planned LNG export project at Lake Charles LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including global natural gas prices and relative spreads, as of the date of our assessment, (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export project and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility. An assessment of these factors in the fourth quarter of 2013 led to a conclusion that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount. We then applied the second step in the goodwill impairment test, allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The assets and liabilities of the reporting unit had recently been measured at fair value in 2012 as a result of the acquisition of Southern Union, and those estimated fair values had been recorded at the reporting unit through the application of “push-down” accounting. For purposes of the hypothetical purchase price allocation used in the goodwill impairment test, we estimated the fair value of the assets and liabilities of the reporting unit in a manner similar to the original purchase price allocation. In allocating value to the property, plant and equipment, we used current replacement costs adjusted for assumed depreciation. We also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. We adjusted deferred income taxes based on these estimated fair values. Based on this hypothetical purchase price allocation, estimated goodwill was $184 million , which was less than the balance of $873 million that had originally been recorded by the reporting unit through “push-down” accounting in 2012. As a result, we recorded a goodwill impairment of $689 million during the fourth quarter of 2013. No other goodwill impairments were identified or recorded for our reporting units. |
Intangible Assets Disclosure [Text Block] | Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our balance sheet the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 2014 December 31, 2013 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 5,067 $ (464 ) $ 2,113 $ (256 ) Patents (9 years) 48 (11 ) 48 (6 ) Trade Names (15 years) 556 (15 ) 66 (12 ) Other (1 to 15 years) 36 (7 ) 7 (4 ) Total amortizable intangible assets $ 5,707 $ (497 ) $ 2,234 $ (278 ) Non-amortizable intangible assets: Trademarks 316 — 294 — Total intangible assets $ 6,023 $ (497 ) $ 2,528 $ (278 ) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2014 2013 2012 Reported in depreciation, depletion and amortization $ 212 $ 117 $ 65 Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2015 $ 263 2016 260 2017 260 2018 259 2019 256 The increase in intangible assets during the year ended December 31, 2014 relates to the acquisitions more fully described in Note 3. We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. |
Other Noncurrent Assets [Policy Text Block] | Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2014 2013 Unamortized financing costs (3 to 30 years) $ 156 $ 126 Regulatory assets 85 86 Deferred charges 220 144 Restricted funds 177 378 Other 148 89 Total other non-current assets, net $ 786 $ 823 Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies. |
Asset Retirement Obligation | Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates. Except for certain amounts recorded by Panhandle, Sunoco Logistics and our retail marketing operations, discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2014 and 2013 , in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time. Below is a schedule of AROs by segment recorded as other non-current liabilities in ETP’s consolidated balance sheet: December 31, 2014 2013 Interstate transportation and storage $ 60 $ 55 Investment in Sunoco Logistics 41 41 Retail marketing 87 84 $ 188 $ 180 Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. As of December 31, 2014 , there were no legally restricted funds for the purpose of settling AROs. |
Accrued and Other Current Liabilities | Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: December 31, 2014 2013 Interest payable $ 382 $ 332 Customer advances and deposits 103 142 Accrued capital expenditures 673 258 Accrued wages and benefits 233 173 Taxes payable other than income taxes 236 211 Income taxes payable 54 4 Deferred income taxes 99 119 Other 319 395 Total accrued and other current liabilities $ 2,099 $ 1,634 Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit. |
Environmental Costs, Policy [Policy Text Block] | Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued. |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2014 was $26.91 billion and $25.98 billion , respectively. As of December 31, 2013 , the aggregate fair value and carrying amount of our debt obligations was $21.02 billion and $20.40 billion , respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the period ended December 31, 2014 , no transfers were made between any levels within the fair value hierarchy. The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2014 and 2013 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 $ 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 Contracts 1 — 1 — Power: Forwards 3 — 3 — Futures 4 4 — — Natural Gas Liquids — Forwards/Swaps 69 46 23 — Refined Products — Futures 21 21 — — Total commodity derivatives 745 632 113 — Total assets $ 748 $ 632 $ 116 $ — Liabilities: Interest rate derivatives $ (155 ) $ — $ (155 ) $ — Embedded derivatives in the ETP Preferred Units (16 ) — — (16 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (18 ) (18 ) — — Swing Swaps IFERC (25 ) (2 ) (23 ) — Fixed Swaps/Futures (490 ) (490 ) — — Power: Forwards (4 ) — (4 ) — Futures (2 ) (2 ) — — Natural Gas Liquids — Forwards/Swaps (32 ) (32 ) — — Refined Products — Futures (7 ) (7 ) — — Total commodity derivatives (578 ) (551 ) (27 ) — Total liabilities $ (749 ) $ (551 ) $ (182 ) $ (16 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 47 $ — $ 47 $ — Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 5 5 — — Swing Swaps IFERC 8 1 7 — Fixed Swaps/Futures 203 201 2 — Natural Gas Liquids — Forwards/Swaps 7 5 2 — Power: Power — Forwards 3 — 3 — Refined Products – Futures 5 5 — — Total commodity derivatives 231 217 14 — Total assets $ 278 $ 217 $ 61 $ — Liabilities: Interest rate derivatives $ (95 ) $ — $ (95 ) $ — Embedded derivatives in the Regency Preferred Units (19 ) — — (19 ) Commodity derivatives: Condensate — Forward Swaps (1 ) — (1 ) — Natural Gas: Basis Swaps IFERC/NYMEX (4 ) (4 ) — — Swing Swaps IFERC (6 ) — (6 ) — Fixed Swaps/Futures (206 ) (201 ) (5 ) — Forward Physical Contracts (1 ) — (1 ) — Natural Gas Liquids — Forwards/Swaps (9 ) (5 ) (4 ) — Power: Power — Forwards (1 ) — (1 ) — Refined Products – Futures (5 ) (5 ) — — Total commodity derivatives (233 ) (215 ) (18 ) — Total liabilities $ (347 ) $ (215 ) $ (113 ) $ (19 ) At December 31, 2013, the fair value of the Lake Charles LNG reporting unit was classified as Level 3 of the fair value hierarchy due to the significance of unobservable inputs developed using company-specific information. We used the income approach to measure the fair value of the Lake Charles LNG reporting unit. Under the income approach, we calculated the fair value based on the present value of the estimated future cash flows. The discount rate used, which was an unobservable input, was based on the weighted-average cost of capital adjusted for the relevant risk associated with business-specific characteristics and the uncertainty related to the business's ability to execute on the projected cash flows. |
Contributions in Aid of Construction Costs | Contributions in Aid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized. |
Shipping and Handling Costs | Shipping and Handling Costs Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses. |
Costs and Expenses | Costs and Expenses Costs of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel. We record the collection of taxes to be remitted to government authorities on a net basis except for our retail marketing segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by our retail marketing segment were $2.46 billion , $2.22 billion and $573 million for the years ended December 31, 2014 , 2013 and 2012 , respectively. |
Income Tax, Policy [Policy Text Block] | Income Taxes ETP is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2014, 2013 and 2012 , our qualifying income met the statutory requirement. The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include Susser and ETP Holdco, which owns Sunoco, Inc. and Panhandle. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes. |
Accounting for Derivative Instruments and Hedging Activities | Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations. |
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block] | Unit-Based Compensation For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets. |
Pension and Other Postretirement Plans, Policy [Policy Text Block] | Pensions and Other Postretirement Benefit Plans Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through AOCI in equity or are reflected as a regulatory asset or regulatory liability for regulated subsidiaries. |
Allocation of Income (Loss) | Allocation of Income For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests. |
Estimates, Significant Accoun26
Estimates, Significant Accounting Policies and Balance Sheet Detials (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |
Net change in operating assets and liabilities (net of acquisitions) | The net change in operating assets and liabilities (net of acquisitions) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2014 2013 2012 Accounts receivable $ 600 $ (557 ) $ 267 Accounts receivable from related companies (22 ) 26 (12 ) Inventories 51 (254 ) (258 ) Exchanges receivable 18 (8 ) 14 Other current assets 132 (58 ) 574 Other non-current assets, net (6 ) (45 ) (30 ) Accounts payable (851 ) 542 (990 ) Accounts payable to related companies 3 (143 ) 101 Exchanges payable (99 ) 128 — Accrued and other current liabilities (92 ) 211 (169 ) Other non-current liabilities (73 ) 147 25 Price risk management assets and liabilities, net 19 (147 ) (15 ) Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (320 ) $ (158 ) $ (493 ) |
Non-cash investing and financing activities and supplemental cash flow information | Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2014 2013 2012 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 643 $ 226 $ 420 Net gains from subsidiary common unit issuances $ 175 $ — $ — AmeriGas limited partner interest received in exchange for contribution of Propane Business $ — $ — $ 1,123 NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the Susser Merger (see Note 3) $ 908 $ — $ — Redemption of Common Units in connection with the Lake Charles LNG Transaction (see Note 3) $ 1,167 $ — $ — Issuance of Common Units in connection with the ETP Holdco Acquisition $ — $ 2,464 $ — Issuance of Class H Units $ — $ 1,514 $ — Long-term debt assumed and non-compete agreement notes payable issued in acquisitions $ 564 $ — $ 6,658 Issuance of Common Units in connection with other acquisitions $ — $ — $ 2,295 Predecessor equity issuance of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions $ 4,281 $ — $ — Long-term debt assumed in PVR Acquisition $ 1,887 $ — $ — Long-term debt exchanged in Eagle Rock Midstream Acquisition $ 499 $ — $ — SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,232 $ 1,049 $ 790 Cash paid for income taxes $ 344 $ 58 $ 23 |
Inventory | Inventories consisted of the following: December 31, 2014 2013 Natural gas and NGLs $ 392 $ 577 Crude oil 364 488 Refined products 392 543 Appliances, parts and fittings, and other 312 199 Total inventories $ 1,460 $ 1,807 |
Other Current Assets | Other current assets consisted of the following: December 31, 2014 2013 Deposits paid to vendors $ 65 $ 49 Deferred income taxes 14 — Prepaid expenses and other 217 262 Total other current assets $ 296 $ 311 |
Components and useful lives of property, plant and equipment | Components and useful lives of property, plant and equipment were as follows: December 31, 2014 2013 Land and improvements $ 1,307 $ 881 Buildings and improvements (1 to 45 years) 1,918 935 Pipelines and equipment (5 to 83 years) 27,164 21,038 Natural gas and NGL storage facilities (5 to 46 years) 1,215 1,083 Bulk storage, equipment and facilities (2 to 83 years) 2,583 1,933 Tanks and other equipment (5 to 40 years) 58 1,697 Retail equipment (2 to 99 years) 515 450 Vehicles (1 to 25 years) 203 156 Right of way (20 to 83 years) 2,445 2,183 Furniture and fixtures (2 to 25 years) 57 51 Linepack 119 118 Pad gas 44 52 Natural resources 454 — Other (1 to 30 years) 979 706 Construction work-in-process 4,343 2,166 43,404 33,449 Less – Accumulated depreciation (4,497 ) (3,113 ) Property, plant and equipment, net $ 38,907 $ 30,336 |
Depreciation expense | We recognized the following amounts of depreciation expense for the periods presented: Years Ended December 31, 2014 2013 2012 Depreciation expense $ 1,459 $ 1,202 $ 783 Capitalized interest, excluding AFUDC $ 101 $ 45 $ 99 Depletion expense related to Regency’s natural resources operations was $11 million for the year ended December 31, 2014. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of coal extracted as compared to the total estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by Regency’s own geologists. Regency’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, Regency carries out core-hole drilling activities on coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. Regency depletes timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. Regency determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. |
Changes in carrying amount of goodwill | Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream Liquids Transportation and Services Investment in Sunoco Logistics Retail Marketing All Other Total Balance, December 31, 2012 $ 10 $ 1,884 $ 688 $ 432 $ 1,368 $ 1,272 $ 742 $ 6,396 Goodwill acquired — — — — — 156 — 156 Goodwill impairment — (689 ) — — — — — (689 ) Other — — (2 ) — (22 ) 17 — (7 ) Balance, December 31, 2013 10 1,195 686 432 1,346 1,445 742 5,856 Goodwill acquired — — 451 — 12 1,862 15 2,340 Goodwill disposed — (184 ) — — — — — (184 ) Goodwill impairment — — (370 ) — — — — (370 ) Balance, December 31, 2014 $ 10 $ 1,011 $ 767 $ 432 $ 1,358 $ 3,307 $ 757 $ 7,642 |
Components and useful lives of intangibles assets | Components and useful lives of intangible assets were as follows: December 31, 2014 December 31, 2013 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 5,067 $ (464 ) $ 2,113 $ (256 ) Patents (9 years) 48 (11 ) 48 (6 ) Trade Names (15 years) 556 (15 ) 66 (12 ) Other (1 to 15 years) 36 (7 ) 7 (4 ) Total amortizable intangible assets $ 5,707 $ (497 ) $ 2,234 $ (278 ) Non-amortizable intangible assets: Trademarks 316 — 294 — Total intangible assets $ 6,023 $ (497 ) $ 2,528 $ (278 ) |
Amortization expense of intangible assets | Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2014 2013 2012 Reported in depreciation, depletion and amortization $ 212 $ 117 $ 65 |
Amortization expense, expected | Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2015 $ 263 2016 260 2017 260 2018 259 2019 256 |
Other non-current assets | Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2014 2013 Unamortized financing costs (3 to 30 years) $ 156 $ 126 Regulatory assets 85 86 Deferred charges 220 144 Restricted funds 177 378 Other 148 89 Total other non-current assets, net $ 786 $ 823 |
Schedule of Asset Retirement Obligations [Table Text Block] | Below is a schedule of AROs by segment recorded as other non-current liabilities in ETP’s consolidated balance sheet: December 31, 2014 2013 Interstate transportation and storage $ 60 $ 55 Investment in Sunoco Logistics 41 41 Retail marketing 87 84 $ 188 $ 180 |
Accounts payable and accrued liabilities | Accrued and other current liabilities consisted of the following: December 31, 2014 2013 Interest payable $ 382 $ 332 Customer advances and deposits 103 142 Accrued capital expenditures 673 258 Accrued wages and benefits 233 173 Taxes payable other than income taxes 236 211 Income taxes payable 54 4 Deferred income taxes 99 119 Other 319 395 Total accrued and other current liabilities $ 2,099 $ 1,634 |
Summary of fair value of financials | The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2014 and 2013 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 $ 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 Contracts 1 — 1 — Power: Forwards 3 — 3 — Futures 4 4 — — Natural Gas Liquids — Forwards/Swaps 69 46 23 — Refined Products — Futures 21 21 — — Total commodity derivatives 745 632 113 — Total assets $ 748 $ 632 $ 116 $ — Liabilities: Interest rate derivatives $ (155 ) $ — $ (155 ) $ — Embedded derivatives in the ETP Preferred Units (16 ) — — (16 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (18 ) (18 ) — — Swing Swaps IFERC (25 ) (2 ) (23 ) — Fixed Swaps/Futures (490 ) (490 ) — — Power: Forwards (4 ) — (4 ) — Futures (2 ) (2 ) — — Natural Gas Liquids — Forwards/Swaps (32 ) (32 ) — — Refined Products — Futures (7 ) (7 ) — — Total commodity derivatives (578 ) (551 ) (27 ) — Total liabilities $ (749 ) $ (551 ) $ (182 ) $ (16 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 47 $ — $ 47 $ — Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 5 5 — — Swing Swaps IFERC 8 1 7 — Fixed Swaps/Futures 203 201 2 — Natural Gas Liquids — Forwards/Swaps 7 5 2 — Power: Power — Forwards 3 — 3 — Refined Products – Futures 5 5 — — Total commodity derivatives 231 217 14 — Total assets $ 278 $ 217 $ 61 $ — Liabilities: Interest rate derivatives $ (95 ) $ — $ (95 ) $ — Embedded derivatives in the Regency Preferred Units (19 ) — — (19 ) Commodity derivatives: Condensate — Forward Swaps (1 ) — (1 ) — Natural Gas: Basis Swaps IFERC/NYMEX (4 ) (4 ) — — Swing Swaps IFERC (6 ) — (6 ) — Fixed Swaps/Futures (206 ) (201 ) (5 ) — Forward Physical Contracts (1 ) — (1 ) — Natural Gas Liquids — Forwards/Swaps (9 ) (5 ) (4 ) — Power: Power — Forwards (1 ) — (1 ) — Refined Products – Futures (5 ) (5 ) — — Total commodity derivatives (233 ) (215 ) (18 ) — Total liabilities $ (347 ) $ (215 ) $ (113 ) $ (19 ) |
Unobservable Inputs of Fair Value Level 3 Liabilities [Table Text Block] | The following table presents the material unobservable inputs used to estimate the fair value of Regency’s Preferred Units and the embedded derivatives in Regency’s Preferred Units: Unobservable Input December 31, 2014 Embedded derivatives in the Regency Preferred Units Credit Spread 4.76 % Volatility 35.80 % Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in Regency’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the Regency Preferred Units. Changes in Regency’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives. |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2014 . There were no transfers between the fair value hierarchy levels during the years ended December 31, 2014 or 2013 . Balance, December 31, 2013 $ (19 ) Net unrealized gains included in other income (expense) 3 Balance, December 31, 2014 $ (16 ) |
Acquisitions and Divestitures27
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Business Acquisition [Line Items] | |
Business Combination, Separately Recognized Transactions [Table Text Block] | The following table presents the revenues and net income (loss) for the previously separate entities and the combined amounts presented herein: Years Ended December 31, 2014 2013 2012 Revenues: Partnership $ 51,158 $ 46,339 $ 15,702 Regency 4,840 2,242 1,309 Adjustments and eliminations (523 ) (246 ) (47 ) Combined $ 55,475 $ 48,335 $ 16,964 Net income (loss): Partnership $ 1,553 $ 767 $ 1,647 Regency (142 ) 64 48 Adjustments and eliminations (112 ) (85 ) (50 ) Combined $ 1,299 $ 746 $ 1,645 |
Selected Financial Data related To Southern Unions Discontinued Operations [Table Text Block] | The following table summarizes selected financial information related to Southern Union’s distribution operations in 2013 through MGE and NEG’s sale dates in September 2013 and December 2013, respectively, and for the period from March 26, 2012 to December 31, 2012: Years Ended December 31, 2013 2012 Revenue from discontinued operations $ 415 $ 324 Net income of discontinued operations, excluding effect of taxes and overhead allocations 65 43 |
Pro Forma Results of Operations | The following unaudited pro forma consolidated results of operations for the years ended December 31, 2014, 2013 and 2012 are presented as if the Sunoco Merger and the ETP Holdco Transaction had been completed on January 1, 2012, and the PVR and Eagle Rock Midstream acquisitions had been completed on January 1, 2013, and assumes there were no other changes in operations. Years Ended December 31, 2014 2013 2012 Revenues $ 56,301 $ 50,473 $ 40,397 Net income 1,151 532 1,240 Net income attributable to partners 1,323 423 817 Basic net income per Limited Partner unit $ 3.99 $ 1.23 $ 3.29 Diluted net income per Limited Partner unit $ 3.97 $ 1.23 $ 3.28 |
Hoover Midstream Acquisition [Member] | |
Business Acquisition [Line Items] | |
Summary Of Preliminary Assets And Liability Acquired | Assets At July 1, 2014 Current assets $ 113 Property, plant and equipment 1,295 Goodwill (1) 59 Total assets acquired 1,467 Liabilities Current liabilities 116 Long-term debt 499 Other non-current liabilities 11 Total liabilities assumed 626 Net assets acquired $ 841 (1) None of the goodwill is expected to be deductible for tax purposes. |
Sunoco and Southern Union Mergers [Member] | |
Business Acquisition [Line Items] | |
Summary Of Preliminary Assets And Liability Acquired | The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates: Sunoco, Inc. (1) Southern Union (2) Current assets $ 7,312 $ 556 Property, plant and equipment 6,686 6,242 Goodwill 2,641 2,497 Intangible assets 1,361 55 Investments in unconsolidated affiliates 240 2,023 Note receivable 821 — Other assets 128 163 19,189 11,536 Current liabilities 4,424 1,348 Long-term debt obligations, less current maturities 2,879 3,120 Deferred income taxes 1,762 1,419 Other non-current liabilities 769 284 Noncontrolling interest 3,580 — 13,414 6,171 Total consideration 5,775 5,365 Cash received 2,714 37 Total consideration, net of cash received $ 3,061 $ 5,328 (1) Includes amounts recorded with respect to Sunoco Logistics. (2) Includes ETP’s acquisition of Citrus. |
Sunoco Merger | |
Business Acquisition [Line Items] | |
Summary Of Preliminary Assets And Liability Acquired | The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date: Susser Total current assets $ 446 Property, plant and equipment 1,069 Goodwill (1) 1,734 Intangible assets 611 Other non-current assets 17 3,877 Total current liabilities 377 Long-term debt, less current maturities 564 Deferred income taxes 488 Other non-current liabilities 39 Noncontrolling interest 626 2,094 Total consideration 1,783 Cash received 67 Total consideration, net of cash received $ 1,716 (1) None of the goodwill is expected to be deductible for tax purposes. |
Investments in Unconsolidated28
Investments in Unconsolidated Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Investments in and Advances to Affiliates, Schedule of Investments [Abstract] | |
Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block] | Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented: December 31, 2014 2013 Current assets $ 889 $ 1,028 Property, plant and equipment, net 10,520 10,778 Other assets 2,687 2,664 Total assets $ 14,096 $ 14,470 Current liabilities $ 1,983 $ 1,039 Non-current liabilities 7,359 8,139 Equity 4,754 5,292 Total liabilities and equity $ 14,096 $ 14,470 Years Ended December 31, 2014 2013 2012 Revenue $ 4,925 $ 4,695 $ 4,492 Operating income 1,071 1,197 863 Net income 577 699 491 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements. |
Net Income Per Limited Partne29
Net Income Per Limited Partner Unit (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Unit, Basic and Diluted | 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: Years Ended December 31, 2014 2013 2012 Income from continuing operations $ 1,235 $ 713 $ 1,754 Less: Income from continuing operations attributable to noncontrolling interest 116 239 20 Less: Income (loss) from continuing operations attributable to predecessor (153 ) 35 39 Income from continuing operations, net of noncontrolling interest and predecessor income (loss) 1,272 439 1,695 General Partner’s interest in income from continuing operations 513 505 463 Class H Unitholder’s interest in income from continuing operations 217 — — Common Unitholders’ interest in income (loss) from continuing operations 542 (66 ) 1,232 Additional earnings allocated (to) from General Partner (4 ) (2 ) 1 Distributions on employee unit awards, net of allocation to General Partner (13 ) (10 ) (9 ) Income (loss) from continuing operations available to Common Unitholders $ 525 $ (78 ) $ 1,224 Weighted average Common Units – basic 331.5 343.4 248.3 Basic income (loss) from continuing operations per Common Unit $ 1.58 $ (0.23 ) $ 4.93 Dilutive effect of unvested Unit Awards 1.3 — 0.7 Weighted average Common Units, assuming dilutive effect of unvested Unit Awards 332.8 343.4 249.0 Diluted income (loss) from continuing operations per Common Unit $ 1.58 $ (0.23 ) $ 4.91 Basic income (loss) from discontinued operations per Common Unit $ 0.19 $ 0.05 $ (0.50 ) Diluted income (loss) from discontinued operations per Common Unit $ 0.19 $ 0.05 $ (0.50 ) |
Debt Obligations (Tables)
Debt Obligations (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Debt Obligations [Abstract] | |
Debt instruments | Our debt obligations consist of the following: December 31, 2014 2013 ETP Debt 8.5% Senior Notes due April 15, 2014 $ — $ 292 5.95% Senior Notes due February 1, 2015 750 750 6.125% Senior Notes due February 15, 2017 400 400 6.7% Senior Notes due July 1, 2018 600 600 9.7% Senior Notes due March 15, 2019 400 400 9.0% Senior Notes due April 15, 2019 450 450 4.15% Senior Notes due October 1, 2020 700 700 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 3.60% Senior Notes due February 1, 2023 800 800 4.9% Senior Notes due February 1, 2024 350 350 7.6% Senior Notes due February 1, 2024 277 277 8.25% Senior Notes due November 15, 2029 267 267 6.625% Senior Notes due October 15, 2036 400 400 7.5% Senior Notes due July 1, 2038 550 550 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 ETP $2.5 billion Revolving Credit Facility due October 27, 2019 570 65 Unamortized premiums, discounts and fair value adjustments, net (1 ) (34 ) 11,459 11,213 Transwestern Debt 5.39% Senior Notes due November 17, 2014 — 88 5.54% Senior Notes due November 17, 2016 125 125 5.64% Senior Notes due May 24, 2017 82 82 5.36% Senior Notes due December 9, 2020 175 175 5.89% Senior Notes due May 24, 2022 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 Unamortized premiums, discounts and fair value adjustments, net (1 ) (1 ) 781 869 Panhandle Debt (1) 6.20% Senior Notes due November 1, 2017 300 300 7.00% Senior Notes due June 15, 2018 400 400 8.125% Senior Notes due June 1, 2019 150 150 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 14, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 99 155 1,184 1,240 Sunoco, Inc. Debt 4.875% Senior Notes due October 15, 2014 — 250 9.625% Senior Notes due April 15, 2015 250 250 5.75% Senior Notes due January 15, 2017 400 400 9.00% Debentures due November 1, 2024 65 65 Unamortized premiums, discounts and fair value adjustments, net 35 70 750 1,035 Sunoco Logistics Debt 8.75% Senior Notes due February 15, 2014 (2) — 175 6.125% Senior Notes due May 15, 2016 175 175 5.50% Senior Notes due February 15, 2020 250 250 4.65% Senior Notes due February 15, 2022 300 300 3.45% Senior Notes due January 15, 2023 350 350 4.25% Senior Notes due April 1, 2024 500 — 6.85% Senior Notes due February 15, 2040 250 250 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.30% Senior Notes due April 1, 2044 700 — 5.35% Senior Notes due May 15, 2045 800 — Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015 (3) 35 35 Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018 150 200 Unamortized premiums, discounts and fair value adjustments, net 100 118 4,260 2,503 Sunoco LP Debt Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019 683 — 683 — Regency Debt 6.875% Senior Notes due December 1, 2018 — 600 5.75% Senior Notes due September 1, 2020 400 400 6.5% Senior Notes due July 15, 2021 500 500 5.875% Senior Notes due March 1, 2022 900 — 5.5% Senior Notes due April 15, 2023 700 700 4.5% Senior Notes due November 1, 2023 600 600 8.375% Senior Notes due June 1, 2020 390 — 6.5% Senior Notes due May 15, 2021 400 — 8.375% Senior Notes due June 1, 2019 499 — 5.0% Senior Notes due October 1, 2022 700 — Regency $2.0 billion Revolving Credit Facility due November 25, 2019 1,504 510 Unamortized premiums, discounts and fair value adjustments, net 48 — 6,641 3,310 Other 223 228 25,981 20,398 Less: current maturities 1,008 637 $ 24,973 $ 19,761 (1) In connection with the Panhandle Merger, Southern Union’s debt obligations were assumed by Panhandle. (2) Sunoco Logistics’ 8.75% senior notes due February 15, 2014 were classified as long-term debt as Sunoco Logistics repaid these notes in February 2014 with borrowings under its $1.50 billion credit facility due November 2018. (3) The Sunoco Logistics $35 million credit facility outstanding amounts were classified as long-term debt as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. |
Future maturities of long-term debt | The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $280 million in unamortized net premiums and fair value adjustments: 2015 $ 1,050 2016 314 2017 1,228 2018 1,155 2019 4,262 Thereafter 17,692 Total $ 25,701 |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Schedule of Capital Units [Table Text Block] | The change in Common Units was as follows: Years Ended December 31, 2014 2013 2012 Number of Common Units, beginning of period 333.8 301.5 225.5 Common Units issued in connection with the Susser Merger (see Note 3) 15.8 — — Common Units redeemed in connection with the Lake Charles LNG Transaction (see Note 3) (18.7 ) — — Common Units issued in connection with public offerings — 13.8 15.5 Common Units issued in connection with certain acquisitions — 49.5 57.4 Common Units redeemed for Class H Units — (50.2 ) — Common Units issued in connection with the Distribution Reinvestment Plan 2.8 2.3 1.0 Common Units issued in connection with Equity Distribution Agreements 21.4 16.9 1.6 Repurchases of Common Units in open-market transactions — (0.4 ) — Issuance of Common Units under equity incentive plans 0.4 0.4 0.5 Number of Common Units, end of period 355.5 333.8 301.5 |
Net Proceeds From Sale Of Units [Text Block] | The following table summarizes our public offerings of Common Units during the periods presented, all of which have been registered under the Securities Act of 1933 (as amended): Date Number of Common Units Price per Unit Net Proceeds July 2012 15.5 $ 44.57 $ 671 April 2013 13.8 48.05 657 Proceeds from the offerings listed above were used to repay amounts outstanding under the ETP Credit Facility and/or to fund capital expenditures and capital contributions to joint ventures, and for general partnership purposes. |
Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block] | Quarter Ended Record Date Payment Date Rate December 31, 2011 February 7, 2012 February 14, 2012 $ 0.8938 March 31, 2012 May 4, 2012 May 15, 2012 0.8938 June 30, 2012 August 6, 2012 August 14, 2012 0.8938 September 30, 2012 November 6, 2012 November 14, 2012 0.8938 December 31, 2012 February 7, 2013 February 14, 2013 0.8938 March 31, 2013 May 6, 2013 May 15, 2013 0.8938 June 30, 2013 August 5, 2013 August 14, 2013 0.8938 September 30, 2013 November 4, 2013 November 14, 2013 0.9050 December 31, 2013 February 7, 2014 February 14, 2014 0.9200 March 31, 2014 May 5, 2014 May 15, 2014 0.9350 June 30, 2014 August 4, 2014 August 14, 2014 0.9550 September 30, 2014 November 3, 2014 November 14, 2014 0.9750 December 31, 2014 February 6, 2015 February 13, 2015 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units. The relinquishments subsequent to the Regency Merger were as follows: Total Year 2015 (for quarters ending subsequent to the Regency Merger on April 30, 2015) $ 56 2016 137 2017 128 2018 105 2019 95 |
Comprehensive Income (Loss) Note [Text Block] | The following table presents the components of AOCI, net of tax: December 31, 2014 2013 Available-for-sale securities $ 3 $ 2 Foreign currency translation adjustment (3 ) (1 ) Net loss on commodity related hedges (1 ) (4 ) Actuarial gain (loss) related to pensions and other postretirement benefits (57 ) 56 Investments in unconsolidated affiliates, net 2 8 Total AOCI, net of tax $ (56 ) $ 61 |
Schedule of taxes related to accumulated other comprehensive income [Table Text Block] | The tables below set forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented: December 31, 2014 2013 Available-for-sale securities $ (1 ) $ (1 ) Foreign currency translation adjustment 2 1 Actuarial gain relating to pension and other postretirement benefits (37 ) (39 ) Total $ (36 ) $ (39 ) |
ETP [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2011 February 7, 2012 February 14, 2012 $ 0.8938 March 31, 2012 May 4, 2012 May 15, 2012 0.8938 June 30, 2012 August 6, 2012 August 14, 2012 0.8938 September 30, 2012 November 6, 2012 November 14, 2012 0.8938 December 31, 2012 February 7, 2013 February 14, 2013 0.8938 March 31, 2013 May 6, 2013 May 15, 2013 0.8938 June 30, 2013 August 5, 2013 August 14, 2013 0.8938 September 30, 2013 November 4, 2013 November 14, 2013 0.9050 December 31, 2013 February 7, 2014 February 14, 2014 0.9200 March 31, 2014 May 5, 2014 May 15, 2014 0.9350 June 30, 2014 August 4, 2014 August 14, 2014 0.9550 September 30, 2014 November 3, 2014 November 14, 2014 0.9750 December 31, 2014 February 6, 2015 February 13, 2015 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 |
Sunoco Logistics [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2012 February 8, 2013 February 14, 2013 $ 0.2725 March 31, 2013 May 9, 2013 May 15, 2013 0.2863 June 30, 2013 August 8, 2013 August 14, 2013 0.3000 September 30, 2013 November 8, 2013 November 14, 2013 0.3150 December 31, 2013 February 10, 2014 February 14, 2014 0.3312 March 31, 2014 May 9, 2014 May 15, 2014 0.3475 June 30, 2014 August 8, 2014 August 14, 2014 0.3650 September 30, 2014 November 7, 2014 November 14, 2014 0.3825 December 31, 2014 February 9, 2015 February 13, 2015 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380 |
Sunoco LP [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014 were as follows: Quarter Ended Record Date Payment Date Rate September 30, 2014 November 18, 2014 November 28, 2014 $ 0.5457 December 31, 2014 February 17, 2015 February 27, 2015 0.6000 March 31, 2015 May 19, 2015 May 29, 2015 0.6450 June 30, 2015 August 18, 2015 August 28, 2015 0.6934 |
Regency | |
Net Proceeds From Sale Of Units [Text Block] | The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented: Date Number of Regency Common Units Price per Regency Unit Net Proceeds March 2012 12.7 $ 24.47 $ 297 |
Unit-Based Compensation Plans32
Unit-Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Deferred Compensation Arrangements [Abstract] | |
Activity of the awards granted to employees and non-employee directors | The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2013 3.2 $ 49.65 Awards granted 1.0 60.85 Awards vested (0.5 ) 48.12 Awards forfeited (0.1 ) 32.36 Unvested awards as of December 31, 2014 3.6 53.83 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows: Years Ended December 31, 2014 2013 2012 Current expense (benefit): Federal $ 321 $ 51 $ (3 ) State 86 (2 ) 4 Total 407 49 1 Deferred expense (benefit): Federal (50 ) (6 ) 45 State 1 54 17 Total (49 ) 48 62 Total income tax expense from continuing operations $ 358 $ 97 $ 63 |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Historically, our effective rate differed from the statutory rate primarily due to Partnership earnings that are not subject to U.S. federal and most state income taxes at the Partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3 ) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2014 and 2013 is as follows: December 31, 2014 December 31, 2013 Corporate Subsidiaries (1) Partnership (2) Consolidated Corporate Subsidiaries (1) Partnership (2) Consolidated Income tax expense (benefit) at U.S. statutory rate of 35 percent $ 217 $ — $ 217 $ (166 ) $ — $ (166 ) Increase (reduction) in income taxes resulting from: Nondeductible goodwill — — — 241 — 241 Nondeductible goodwill included in the Lake Charles LNG Transaction 105 — 105 — — — State income taxes (net of federal income tax effects) 9 45 54 31 5 36 Premium on debt retirement (10 ) — (10 ) — — — Foreign (8 ) — (8 ) — — — Other — — — (13 ) (1 ) (14 ) Income tax from continuing operations $ 313 $ 45 $ 358 $ 93 $ 4 $ 97 (1) Includes ETP Holdco, Susser, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd., Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. ETP Holdco, which was formed via the Sunoco Merger and the ETP Holdco Transaction (see Note 3 ), includes Sunoco, Inc. and Panhandle. ETE held a 60% interest in ETP Holdco until April 30, 2013. Subsequent to the ETP Holdco Acquisition (see Note 3 ) on April 30, 2013, ETP owns 100% of ETP Holdco. (2) Includes ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes. |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2014 2013 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 116 $ 217 Pension and other postretirement benefits 47 57 Long term debt 53 108 Other 111 104 Total deferred income tax assets 327 486 Valuation allowance (84 ) (74 ) Net deferred income tax assets $ 243 $ 412 Deferred income tax liabilities: Properties, plants and equipment $ (1,506 ) $ (1,544 ) Inventory (153 ) (302 ) Investment in unconsolidated affiliates (2,528 ) (2,244 ) Trademarks (355 ) (180 ) Other (32 ) (45 ) Total deferred income tax liabilities (4,574 ) (4,315 ) Net deferred income tax liability (4,331 ) (3,903 ) Less: current portion of deferred income tax liabilities, net (85 ) (119 ) Accumulated deferred income taxes $ (4,246 ) $ (3,784 ) |
Balance Sheet Classification of Deferred Taxes [Table Text Block] | The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3 ) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows: December 31, 2014 2013 Net deferred income tax liability, beginning of year $ (3,903 ) $ (3,628 ) Susser acquisition (488 ) — SUGS Contribution to Regency — (115 ) Tax provision (including discontinued operations) 60 (111 ) Other — (49 ) Net deferred income tax liability $ (4,331 ) $ (3,903 ) |
Schedule of Unrecognized Tax Benefits Rollforward [Table Text Block] | The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2014 2013 2012 Balance at beginning of year $ 429 $ 27 $ 2 Additions attributable to acquisitions — — 28 Additions attributable to tax positions taken in the current year 20 — — Additions attributable to tax positions taken in prior years (1 ) 406 — Settlements (5 ) — — Lapse of statute (3 ) (4 ) (3 ) Balance at end of year $ 440 $ 429 $ 27 |
Regulatory Matters, Commitmen34
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
Operating Leases of Lessee Disclosure [Table Text Block] | We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058 . The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: Years Ended December 31, 2014 2013 2012 Rental expense (1) $ 159 $ 151 $ 60 Less: Sublease rental income (26 ) (24 ) (4 ) Rental expense, net $ 133 $ 127 $ 56 (1) Includes contingent rentals totaling $24 million , $22 million and $6 million for the years ended December 31, 2014 , 2013 and 2012 , respectively. |
Future Minimum Lease Commitments | Future minimum lease commitments for such leases are: Years Ending December 31: 2015 $ 151 2016 129 2017 118 2018 108 2019 102 Thereafter 829 Future minimum lease commitments 1,437 Less: Sublease rental income (34 ) Net future minimum lease commitments $ 1,403 |
Environmental Exit Costs by Cost [Table Text Block] | The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. December 31, 2014 2013 Current $ 41 $ 47 Non-current 360 356 Total environmental liabilities $ 401 $ 403 |
Price risk management assets 35
Price risk management assets and liabilties (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Derivative [Line Items] | |
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block] | Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Years Ended December 31, 2014 2013 2012 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ (3 ) $ 4 $ 14 Total $ (3 ) $ 4 $ 14 |
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2014 2013 2012 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ (8 ) $ 8 $ 54 Total $ (8 ) $ 8 $ 54 |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Years Ended December 31, 2014 2013 2012 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (6 ) $ (11 ) $ (7 ) Commodity derivatives – Non-trading Cost of products sold 199 (21 ) 26 Commodity contracts – Non-trading Deferred gas purchases — (3 ) (26 ) Interest rate derivatives Gains (losses) on interest rate derivatives (157 ) 53 (19 ) Embedded derivatives Other income 3 6 14 Total $ 39 $ 24 $ (12 ) |
Outstanding commodity-related derivatives | The following table details the outstanding commodity-related derivatives related to ETP’s legacy operations and Regency’s operations: ETP Legacy Operations December 31, 2014 December 31, 2013 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (232,500 ) 2015 9,457,500 2014-2019 Basis Swaps IFERC/NYMEX (1) (13,907,500 ) 2015-2016 (487,500 ) 2014-2017 Swing Swaps — — 1,937,500 2014-2016 Options – Calls 5,000,000 2015 — — Power (Megawatt): Forwards 288,775 2015 351,050 2014 Futures (156,000 ) 2015 (772,476 ) 2014 Options – Puts (72,000 ) 2015 (52,800 ) 2014 Options – Calls 198,556 2015 103,200 2014 Crude (Bbls) – Futures — — 103,000 2014 (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX 57,500 2015 570,000 2014 Swing Swaps IFERC 46,150,000 2015 (9,690,000 ) 2014-2016 Fixed Swaps/Futures (8,779,000 ) 2015-2016 (8,195,000 ) 2014-2015 Forward Physical Contracts (9,116,777 ) 2015 5,668,559 2014-2015 Natural Gas Liquid (Bbls) – Forwards/Swaps (2,179,400 ) 2015 (1,133,600 ) 2014 Refined Products (Bbls) – Futures 13,745,755 2015 (280,000 ) 2014 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (39,287,500 ) 2015 (7,352,500 ) 2014 Fixed Swaps/Futures (39,287,500 ) 2015 (50,530,000 ) 2014 Hedged Item – Inventory 39,287,500 2015 50,530,000 2014 Cash Flow Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX — — (1,825,000 ) 2014 Fixed Swaps/Futures — — (12,775,000 ) 2014 Natural Gas Liquid (Bbls) – Forwards/Swaps — — (780,000 ) 2014 Crude (Bbls) – Futures — — (30,000 ) 2014 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. Regency Operations December 31, 2014 December 31, 2013 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Non-Trading) Natural Gas (MMBtu) — Fixed Swaps/Futures (25,525,000 ) 2015 (24,455,000 ) 2014-2015 Propane (Gallons) — Forwards/Swaps (29,148,000 ) 2015 (52,122,000 ) 2014-2015 NGLs (Barrels) — Forwards/Swaps (292,000 ) 2015 (438,000 ) 2014 WTI Crude Oil (Barrels) — Forwards/Swaps (1,252,000 ) 2015-2016 (521,000 ) 2014 |
Interest rate swaps outstanding | Entity Term Type (1) Notional Amount Outstanding December 31, 2014 December 31, 2013 ETP July 2014 (2) Forward-starting to pay a fixed rate of 4.25% and receive a floating rate $ — $ 400 ETP July 2015 (2) Forward-starting to pay a fixed rate of 3.38% and receive a floating rate 200 — ETP July 2016 (3) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 200 — ETP July 2017 (4) Forward-starting to pay a fixed rate of 3.84% and receive a floating rate 300 — ETP July 2018 (4) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 — ETP July 2019 (4) Forward-starting to pay a fixed rate of 3.19% and receive a floating rate 300 — ETP July 2018 Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% — 600 ETP June 2021 Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% — 400 ETP February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% 200 400 Panhandle November 2021 Pay a fixed rate of 3.82% and receive a floating rate — 275 |
Fair Value of derivative instruments | The following table provides a summary of our derivative assets and liabilities: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives December 31, 2014 December 31, 2013 December 31, 2014 December 31, 2013 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 43 $ 2 $ — $ (20 ) 43 2 — (20 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) $ 617 $ 227 $ (577 ) $ (209 ) Commodity derivatives 107 43 (23 ) (45 ) Interest rate derivatives 3 47 (155 ) (95 ) Embedded derivatives in Regency Preferred Units — — (16 ) (19 ) 727 317 (771 ) (368 ) Total derivatives $ 770 $ 319 $ (771 ) $ (388 ) |
Offsetting Assets Table Text Block [Table Text Block] | The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2014 December 31, 2013 December 31, 2014 December 31, 2013 Derivatives in offsetting agreements: OTC contracts Price risk management assets (liabilities) $ 23 $ 42 $ (23 ) $ (38 ) Broker cleared derivative contracts Other current assets 674 264 (574 ) (318 ) 697 306 (597 ) (356 ) Offsetting agreements: Counterparty netting Price risk management assets (liabilities) (19 ) (36 ) 19 36 Payments on margin deposit Other current assets 5 (1 ) (22 ) 55 (14 ) (37 ) (3 ) 91 Net derivatives with offsetting agreements 683 269 (600 ) (265 ) Derivatives without offsetting agreements 87 50 (171 ) (123 ) Total derivatives $ 770 $ 319 $ (771 ) $ (388 ) |
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss) [Table Text Block] | The following tables summarize the amounts recognized with respect to our derivative financial instruments: Change in Value Recognized in OCI on Derivatives (Effective Portion) Years Ended December 31, 2014 2013 2012 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ (1 ) $ 8 Total $ — $ (1 ) $ 8 |
Retirement Benefits Retirement
Retirement Benefits Retirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Compensation and Retirement Disclosure [Abstract] | |
Schedule of Defined Benefit Plans Disclosures [Table Text Block] | The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2014 December 31, 2013 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 632 $ 61 $ 223 $ 1,117 $ 78 $ 296 Service cost — — — 3 — — Interest cost 28 3 5 33 2 6 Amendments — — 1 — — 2 Benefits paid, net (45 ) (9 ) (28 ) (99 ) (16 ) (26 ) Actuarial (gain) loss and other 130 10 2 (74 ) (3 ) (14 ) Settlements (27 ) — — (95 ) — — Dispositions — — (1 ) (253 ) — (41 ) Benefit obligation at end of period 718 65 202 632 61 223 Change in plan assets: Fair value of plan assets at beginning of period 600 — 284 906 — 312 Return on plan assets and other 70 — 6 43 — 17 Employer contributions — — 8 — — 8 Benefits paid, net (45 ) — (28 ) (99 ) — (26 ) Settlements (27 ) — — (95 ) — — Dispositions — — (5 ) (155 ) — (27 ) Fair value of plan assets at end of period 598 — 265 600 — 284 Amount underfunded (overfunded) at end of period $ 120 $ 65 $ (63 ) $ 32 $ 61 $ (61 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 90 $ — $ — $ 86 Current liabilities — (9 ) (2 ) — (9 ) (2 ) Non-current liabilities (120 ) (56 ) (25 ) (32 ) (52 ) (23 ) $ (120 ) $ (65 ) $ 63 $ (32 ) $ (61 ) $ 61 Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: Net actuarial gain $ 18 $ 7 $ (20 ) $ (86 ) $ (4 ) $ (25 ) Prior service cost — — 17 — — 18 $ 18 $ 7 $ (3 ) $ (86 ) $ (4 ) $ (7 ) |
Schedule of Accumulated and Projected Benefit Obligations [Table Text Block] | The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2014 December 31, 2013 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 718 $ 65 N/A $ 632 61 N/A Accumulated benefit obligation 718 65 202 632 61 $ 223 Fair value of plan assets 598 — 265 600 — 284 |
Schedule of Net Benefit Costs [Table Text Block] | Components of Net Periodic Benefit Cost December 31, 2014 December 31, 2013 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ — $ — $ 3 $ — Interest cost 31 5 35 6 Expected return on plan assets (40 ) (8 ) (54 ) (9 ) Prior service cost amortization — 1 — 1 Actuarial loss amortization (1 ) (1 ) 2 — Settlements (4 ) — (2 ) — (14 ) (3 ) (16 ) (2 ) Regulatory adjustment (1) — — 5 — Net periodic benefit cost $ (14 ) $ (3 ) $ (11 ) $ (2 ) (1) Southern Union, the predecessor of Panhandle, historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its distribution operations. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission. |
Schedule of Benefit Obligations Assumptions [Table Text Block] | The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2014 December 31, 2013 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.62 % 2.24 % 4.65 % 2.33 % Rate of compensation increase N/A N/A N/A N/A |
Schedule or Description of Weighted Average Discount Rate [Table Text Block] | The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2014 December 31, 2013 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 4.65 % 3.02 % 3.50 % 2.68 % Expected return on assets: Tax exempt accounts 7.50 % 7.00 % 7.50 % 6.95 % Taxable accounts N/A 4.50 % N/A 4.42 % Rate of compensation increase N/A N/A N/A N/A |
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block] | The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: December 31, 2014 2013 Health care cost trend rate 7.09 % 7.57 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.41 % 5.42 % Year that the rate reaches the ultimate trend rate 2018 2018 |
Fair Value of Plan Assets [Table Text Block] | The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 25 $ 25 $ — $ — Mutual funds (1) 110 — 110 — Fixed income securities 463 — 463 — Total $ 598 $ 25 $ 573 $ — (1) Primarily comprised of approximately 100% equities as of December 31, 2014 . Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy Fair Value as of December 31, 2013 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 12 $ 12 $ — $ — Mutual funds (1) 368 — 281 87 Fixed income securities 220 — 220 — Total $ 600 $ 12 $ 501 $ 87 (1) Primarily comprised of approximately 41% equities, 45% fixed income securities, and 14% in other investments as of December 31, 2013 . The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 9 $ 9 $ — $ — Mutual funds (1) 131 131 — — Fixed income securities 125 — 125 — Total $ 265 $ 140 $ 125 $ — (1) Primarily comprised of approximately 56% equities, 38% fixed income securities and 6% cash as of December 31, 2014 . Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy Fair Value as of December 31, 2013 Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 10 $ 10 $ — $ — Mutual funds (1) 130 112 18 — Fixed income securities 144 — 144 — Total $ 284 $ 122 $ 162 $ — (1) Primarily comprised of approximately 41% equities, 48% fixed income securities, 6% cash, and 5% in other investments as of December 31, 2013 . The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. See Note 2 for information related to the framework used to measure the fair value of its pension and other postretirement plan assets. |
Schedule of Expected Benefit Payments [Table Text Block] | Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Pension Benefits Years Funded Plans Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2015 $ 717 $ 9 $ 28 2016 — 8 26 2017 — 7 25 2018 — 7 23 2019 — 6 22 2020 – 2024 — 23 65 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Related Party Transactions [Abstract] | |
Schedule Of Related Party Transactions By Related Party [Table Text Block] | The following table summarizes the affiliate revenues on our consolidated statements of operations: Years Ended December 31, 2014 2013 2012 Affiliated revenues $ 965 $ 1,442 $ 188 |
Related Party Balances For Period Presented [Table Text Block] | The following table summarizes the related company balances on our consolidated balance sheets: December 31, 2014 2013 Accounts receivable from related companies: ETE $ 11 $ 18 Dakota Access Pipeline 68 — PES 6 7 FGT 9 29 ET Crude Oil 10 24 Lake Charles LNG 3 — Other 32 39 Total accounts receivable from related companies: $ 139 $ 117 Accounts payable to related companies: ETE $ — $ 10 FGT 2 8 Lake Charles LNG 2 — Other 21 7 Total accounts payable to related companies: $ 25 $ 25 |
Reportable Segments (Tables)
Reportable Segments (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
Reportable Segments [Abstract] | |
Reportable segments | The following tables present financial information by segment: Years Ended December 31, 2014 2013 2012 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,645 $ 2,242 $ 2,010 Intersegment revenues 212 210 181 2,857 2,452 2,191 Interstate transportation and storage: Revenues from external customers 1,057 1,270 1,109 Intersegment revenues 15 39 — 1,072 1,309 1,109 Midstream: Revenues from external customers 4,770 3,220 2,869 Intersegment revenues 2,053 1,056 208 6,823 4,276 3,077 Liquids transportation and services: Revenues from external customers 3,730 2,025 619 Intersegment revenues 181 101 31 3,911 2,126 650 Investment in Sunoco Logistics: Revenues from external customers 17,920 16,480 3,109 Intersegment revenues 168 159 80 18,088 16,639 3,189 Retail marketing: Revenues from external customers 22,484 21,004 5,926 Intersegment revenues 3 8 — 22,487 21,012 5,926 All other: Revenues from external customers 2,869 2,094 1,322 Intersegment revenues 462 503 440 3,331 2,597 1,762 Eliminations (3,094 ) (2,076 ) (940 ) Total revenues $ 55,475 $ 48,335 $ 16,964 Years Ended December 31, 2014 2013 2012 Cost of products sold: Intrastate transportation and storage $ 2,169 $ 1,737 $ 1,394 Midstream 4,893 3,130 2,120 Liquids transportation and services 3,166 1,654 361 Investment in Sunoco Logistics 17,110 15,574 2,885 Retail marketing 21,154 20,150 5,757 All other 2,975 2,337 1,511 Eliminations (3,078 ) (2,028 ) (940 ) Total cost of products sold $ 48,389 $ 42,554 $ 13,088 Years Ended December 31, 2014 2013 2012 Depreciation, depletion and amortization: Intrastate transportation and storage $ 125 $ 122 $ 122 Interstate transportation and storage 203 244 209 Midstream 569 335 277 Liquids transportation and services 113 91 53 Investment in Sunoco Logistics 296 265 63 Retail marketing 189 114 28 All other 174 125 106 Total depreciation and amortization $ 1,669 $ 1,296 $ 858 Years Ended December 31, 2014 2013 2012 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 27 $ 30 $ 33 Interstate transportation and storage 196 182 162 Midstream 10 1 (10 ) Liquids transportation and services (3 ) (2 ) 2 Investment in Sunoco Logistics 23 18 5 Retail marketing 2 2 1 All other 77 5 19 Total equity in earnings of unconsolidated affiliates $ 332 $ 236 $ 212 Years Ended December 31, 2014 2013 2012 Segment Adjusted EBITDA: Intrastate transportation and storage $ 559 $ 521 $ 667 Interstate transportation and storage 1,212 1,368 1,117 Midstream 1,349 766 613 Liquids transportation and services 591 350 209 Investment in Sunoco Logistics 971 871 219 Retail marketing 731 325 109 All other 297 203 205 Total Segment Adjusted EBITDA 5,710 4,404 3,139 Depreciation, depletion and amortization (1,669 ) (1,296 ) (858 ) Interest expense, net of interest capitalized (1,165 ) (1,013 ) (788 ) Gain on deconsolidation of Propane Business — — 1,057 Gain on sale of AmeriGas common units 177 87 — Goodwill impairment (370 ) (689 ) — Gains (losses) on interest rate derivatives (157 ) 44 (4 ) Non-cash unit-based compensation expense (68 ) (54 ) (47 ) Unrealized gains (losses) on commodity risk management activities 112 42 2 Inventory valuation adjustments (473 ) 3 (75 ) Loss on extinguishment of debt (25 ) (7 ) (124 ) Non-operating environmental remediation — (168 ) — Adjusted EBITDA related to discontinued operations (27 ) (76 ) (99 ) Adjusted EBITDA related to unconsolidated affiliates (748 ) (722 ) (646 ) Equity in earnings of unconsolidated affiliates 332 236 212 Other, net (36 ) 19 48 Income from continuing operations before income tax expense $ 1,593 $ 810 $ 1,817 December 31, 2014 2013 2012 Assets: Intrastate transportation and storage $ 4,984 $ 5,048 $ 5,340 Interstate transportation and storage 10,779 11,537 12,376 Midstream 15,562 7,847 7,189 Liquids transportation and services 4,568 4,321 3,742 Investment in Sunoco Logistics 13,619 11,650 10,291 Retail marketing 8,930 3,936 3,926 All other 4,232 5,561 5,530 Total assets $ 62,674 $ 49,900 $ 48,394 Years Ended December 31, 2014 2013 2012 Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis): Intrastate transportation and storage $ 169 $ 47 $ 37 Interstate transportation and storage 411 152 133 Midstream 1,298 1,114 1,633 Liquids transportation and services 427 448 1,306 Investment in Sunoco Logistics 2,510 1,018 139 Retail marketing 259 176 58 All other 420 372 227 Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs $ 5,494 $ 3,327 $ 3,533 December 31, 2014 2013 2012 Advances to and investments in unconsolidated affiliates: Intrastate transportation and storage $ 423 $ 443 $ 652 Interstate transportation and storage 2,649 2,588 2,723 Midstream 138 36 36 Liquids transportation and services 31 29 29 Investment in Sunoco Logistics 226 125 118 Retail marketing 19 22 21 All other 274 807 1,189 Total advances to and investments in unconsolidated affiliates $ 3,760 $ 4,050 $ 4,768 |
Quarterly Financial Data (Table
Quarterly Financial Data (Tables) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Data [Abstract] | ||
Schedule of Quarterly Financial Information [Table Text Block] | Quarters Ended March 31 June 30 September 30 December 31 Total Year 2014: Revenues $ 13,027 $ 14,088 $ 14,933 $ 13,427 $ 55,475 Gross profit 1,585 1,737 1,919 1,845 7,086 Operating income 706 769 809 159 2,443 Net income 483 548 513 (245 ) 1,299 Common Unitholders’ interest in net income (loss) 253 295 148 (90 ) 606 Basic net income (loss) per Common Unit $ 0.76 $ 0.92 $ 0.44 $ (0.28 ) $ 1.77 Diluted net income (loss) per Common Unit $ 0.76 $ 0.92 $ 0.44 $ (0.28 ) $ 1.77 | Quarters Ended March 31 June 30 September 30 December 31 Total Year 2013: Revenues $ 11,179 $ 12,063 $ 12,486 $ 12,607 $ 48,335 Gross profit 1,372 1,497 1,422 1,490 5,781 Operating income (loss) 541 671 545 (138 ) 1,619 Net income (loss) 402 411 415 (482 ) 746 Common Unitholders’ interest in net income (loss) 194 165 209 (666 ) (98 ) Basic net income (loss) per Common Unit $ 0.63 $ 0.53 $ 0.55 $ (1.90 ) $ (0.18 ) Diluted net income (loss) per Common Unit $ 0.63 $ 0.53 $ 0.55 $ (1.90 ) $ (0.18 ) |
Operations and Organization (Na
Operations and Organization (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2014 | |
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% |
Susser [Member] | |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% |
Sunoco LP [Member] | |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 42.80% |
Fayetteville Express Pipeline, LLC [Member] | FEP [Member] | |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% |
Citrus Corp [Member] | Citrus [Member] | |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% |
Estimates, Significant Accoun41
Estimates, Significant Accounting Policies and Balance Sheet Detials (Narrative) (Details) - Significant Acquisitions and Disposals, Transaction [Domain] - Business Acquisition, Acquiree [Domain] - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Aug. 29, 2014 | Mar. 21, 2014 | |
Inventory Write-down | $ 473 | ||||
Goodwill impairment | 370 | $ 689 | $ 0 | ||
Net increase in goodwill | 1,790 | ||||
Goodwill, Written off Related to Sale of Business Unit | 184 | ||||
Long-term Debt, Fair Value | 26,910 | 21,020 | |||
Goodwill acquired | 2,340 | 156 | |||
GOODWILL | 7,642 | 5,856 | 6,396 | ||
Long-term Debt | $ 25,981 | 20,398 | |||
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member] | |||||
Useful Lives | 3 years | ||||
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member] | |||||
Useful Lives | 46 years | ||||
Maximum [Member] | Patents [Member] | |||||
Useful Lives | 9 years | ||||
Interstate Transportation and Storage [Member] | |||||
Goodwill impairment | $ 0 | ||||
Goodwill, Written off Related to Sale of Business Unit | 184 | ||||
Goodwill acquired | 0 | 0 | |||
GOODWILL | 1,011 | 1,195 | 1,884 | ||
Midstream [Member] | |||||
Goodwill impairment | 0 | ||||
Goodwill, Written off Related to Sale of Business Unit | 0 | ||||
Goodwill acquired | 451 | 0 | |||
GOODWILL | 767 | 686 | 688 | ||
Retail Marketing [Member] | |||||
Excise Taxes Collected | 2,460 | 2,220 | 573 | ||
Goodwill impairment | 0 | 0 | |||
Goodwill, Written off Related to Sale of Business Unit | 0 | ||||
Goodwill acquired | 1,862 | 156 | |||
GOODWILL | 3,307 | 1,445 | $ 1,272 | ||
Lake Charles LNG | |||||
GOODWILL | 873 | 184 | |||
Regency | |||||
Goodwill impairment | 370 | ||||
Long-term Debt | 6,641 | $ 3,310 | |||
PVR Acquisition [Member] | |||||
Goodwill1 | $ 370 | $ 370 | |||
Susser Merger | |||||
Goodwill1 | $ 1,734 | ||||
Investment In Regency [Member] | |||||
Goodwill impairment | $ 370 |
Estimates, Significant Accoun42
Estimates, Significant Accounting Policies and Balance Sheet Detials (Net change in operating assets and liabilities (net of acquisitions) included in cash flows) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |||
Accounts receivable | $ 600 | $ (557) | $ 267 |
Accounts receivable from related companies | (22) | 26 | (12) |
Inventories | 51 | (254) | (258) |
Exchanges receivable | 18 | (8) | 14 |
Other current assets | 132 | (58) | 574 |
Other non-current assets, net | (6) | (45) | (30) |
Accounts payable | (851) | 542 | (990) |
Accounts payable to related companies | 3 | (143) | 101 |
Exchanges payable | (99) | 128 | 0 |
Accrued and other current liabilities | (92) | 211 | (169) |
Other non-current liabilities | (73) | 147 | 25 |
Price risk management assets and liabilities, net | 19 | (147) | (15) |
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ (320) | $ (158) | $ (493) |
Estimates, Significant Accoun43
Estimates, Significant Accounting Policies and Balance Sheet Detials (Non-cash investing and financing activities and supplemental cash flow information) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Accrued capital expenditures | $ 643 | $ 226 | $ 420 |
Net gains from subsidiary common unit issuances | 175 | 0 | 0 |
Issuance of Common Units in connection with acquisitions | 7 | ||
Lake Charles LNG Transaction (see Note 3) | 1,167 | 0 | 0 |
Noncash or Part Noncash Acquisition, Debt Assumed | 1,887 | 0 | 0 |
Long term debt exchanged in connection with acquisitions | 499 | 0 | 0 |
SUPPLEMENTAL CASH FLOW INFORMATION: | |||
Cash paid for interest, net of interest capitalized | 1,232 | 1,049 | 790 |
Cash paid for income taxes | 344 | 58 | 23 |
Common Unitholders | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Noncash or Part Noncash Acquisition, Debt Assumed | 564 | 0 | 6,658 |
ETP's Propane Operations [Member] | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
AmeriGas limited partner interest received in exchange for contribution of Propane Business | 0 | 0 | 1,123 |
Susser Merger | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | 908 | 0 | 0 |
ETP Holdco Acquisition and SUGS Contribution | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | 0 | 2,464 | 0 |
Other Acquisitions [Member] | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | 0 | 0 | 2,295 |
Predecessor Equity Issued in Acquisitions | 4,281 | 0 | 0 |
Class H Units | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | 0 | $ 1,514 | 0 |
General Partner | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Issuance of Common Units in connection with acquisitions | $ 0 | ||
Lake Charles LNG Transaction (see Note 3) | 0 | ||
PVR Acquisition [Member] | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Predecessor Equity Issued in Acquisitions | 3,906 | ||
PVR Acquisition [Member] | General Partner | |||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||
Predecessor Equity Issued in Acquisitions | $ 0 |
Estimates, Significant Accoun44
Estimates, Significant Accounting Policies and Balance Sheet Detials (Inventory) (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | ||
Natural gas and NGLs | $ 392 | $ 577 |
Crude oil | 364 | 488 |
Inventory, refined products | 392 | 543 |
Appliances, parts and fittings, and other | 312 | 199 |
Total inventories | $ 1,460 | $ 1,807 |
Estimates, Significant Accoun45
Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Current Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | ||
Deposits paid to vendors | $ 65 | $ 49 |
Deferred income taxes | 14 | 0 |
Prepaid expenses and other | 217 | 262 |
Total other current assets | $ 296 | $ 311 |
Estimates, Significant Accoun46
Estimates, Significant Accounting Policies and Balance Sheet Detials (Components and useful lives of property, plant and equipment) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Property, Plant and Equipment, Gross | $ 43,404 | $ 33,449 | |
Less - Accumulated depreciation | (4,497) | (3,113) | |
Property, plant and equipment, net | 38,907 | 30,336 | |
Depreciation expense | 1,459 | 1,202 | $ 783 |
Capitalized interest, excluding AFUDC | 101 | 45 | $ 99 |
Land and Land Improvements [Member] | |||
Property, Plant and Equipment, Gross | 1,307 | 881 | |
Building and Building Improvements [Member] | |||
Property, Plant and Equipment, Gross | 1,918 | 935 | |
Pipelines and equipment[Member] | |||
Property, Plant and Equipment, Gross | 27,164 | 21,038 | |
Natural gas and NGL storage [Member] | |||
Property, Plant and Equipment, Gross | 1,215 | 1,083 | |
Bulk Storage, equipment and facilities [Member] | |||
Property, Plant and Equipment, Gross | 2,583 | 1,933 | |
Tanks and other equipment [Member] | |||
Property, Plant and Equipment, Gross | 58 | 1,697 | |
Retail Equipment [Member] | |||
Property, Plant and Equipment, Gross | 515 | 450 | |
Vehicles [Member] | |||
Property, Plant and Equipment, Gross | 203 | 156 | |
Right of way [Member] | |||
Property, Plant and Equipment, Gross | 2,445 | 2,183 | |
Furniture and fixtures [Member] | |||
Property, Plant and Equipment, Gross | 57 | 51 | |
Linepack [Member] | |||
Property, Plant and Equipment, Gross | 119 | 118 | |
Pad gas [Member] | |||
Property, Plant and Equipment, Gross | 44 | 52 | |
Natural Resources [Member] | |||
Property, Plant and Equipment, Gross | 454 | 0 | |
Property, Plant and Equipment, Other Types [Member] | |||
Property, Plant and Equipment, Gross | 979 | 706 | |
Construction Work-In-Process [Member] | |||
Property, Plant and Equipment, Gross | $ 4,343 | $ 2,166 | |
Minimum [Member] | Building and Building Improvements [Member] | |||
Property, plant and equipment useful life, minimum in years | 5 years | ||
Minimum [Member] | Pipelines and equipment[Member] | |||
Property, plant and equipment useful life, minimum in years | 5 years | ||
Minimum [Member] | Natural gas and NGL storage [Member] | |||
Property, plant and equipment useful life, minimum in years | 5 years | ||
Minimum [Member] | Bulk Storage, equipment and facilities [Member] | |||
Property, plant and equipment useful life, minimum in years | 2 years | ||
Minimum [Member] | Tanks and other equipment [Member] | |||
Property, plant and equipment useful life, minimum in years | 5 years | ||
Minimum [Member] | Retail Facilities [Member] | |||
Property, plant and equipment useful life, minimum in years | 3 years | ||
Minimum [Member] | Vehicles [Member] | |||
Property, plant and equipment useful life, minimum in years | 1 year | ||
Minimum [Member] | Right of way [Member] | |||
Property, plant and equipment useful life, minimum in years | 20 years | ||
Minimum [Member] | Furniture and fixtures [Member] | |||
Property, plant and equipment useful life, minimum in years | 2 years | ||
Minimum [Member] | Property, Plant and Equipment, Other Types [Member] | |||
Property, plant and equipment useful life, minimum in years | 1 year | ||
Maximum [Member] | Building and Building Improvements [Member] | |||
Property, plant and equipment useful life, minimum in years | 45 years | ||
Maximum [Member] | Pipelines and equipment[Member] | |||
Property, plant and equipment useful life, minimum in years | 83 years | ||
Maximum [Member] | Natural gas and NGL storage [Member] | |||
Property, plant and equipment useful life, minimum in years | 46 years | ||
Maximum [Member] | Bulk Storage, equipment and facilities [Member] | |||
Property, plant and equipment useful life, minimum in years | 83 years | ||
Maximum [Member] | Tanks and other equipment [Member] | |||
Property, plant and equipment useful life, minimum in years | 40 years | ||
Maximum [Member] | Retail Facilities [Member] | |||
Property, plant and equipment useful life, minimum in years | 99 years | ||
Maximum [Member] | Vehicles [Member] | |||
Property, plant and equipment useful life, minimum in years | 25 years | ||
Maximum [Member] | Right of way [Member] | |||
Property, plant and equipment useful life, minimum in years | 83 years | ||
Maximum [Member] | Furniture and fixtures [Member] | |||
Property, plant and equipment useful life, minimum in years | 25 years | ||
Maximum [Member] | Property, Plant and Equipment, Other Types [Member] | |||
Property, plant and equipment useful life, minimum in years | 48 years |
Estimates, Significant Accoun47
Estimates, Significant Accounting Policies and Balance Sheet Detials (Schedule of Property, Plant and Equipment Depreciation and Capitalized Interest Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |||
Depreciation expense | $ 1,459 | $ 1,202 | $ 783 |
Capitalized interest, excluding AFUDC | $ 101 | $ 45 | $ 99 |
Estimates, Significant Accoun48
Estimates, Significant Accounting Policies and Balance Sheet Detials (Changes in the carrying amount of goodwill) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Goodwill, Beginning Balance | $ 5,856 | $ 6,396 | |
Goodwill acquired | 2,340 | 156 | |
Goodwill impairment | (370) | (689) | $ 0 |
Goodwill, Written off Related to Sale of Business Unit | (184) | ||
Other | (7) | ||
Goodwill, Ending Balance | 7,642 | 5,856 | 6,396 |
Intrastate Transportation And Storage [Member] | |||
Goodwill, Beginning Balance | 10 | 10 | |
Goodwill acquired | 0 | 0 | |
Goodwill impairment | 0 | 0 | |
Goodwill, Written off Related to Sale of Business Unit | 0 | ||
Other | 0 | ||
Goodwill, Ending Balance | 10 | 10 | 10 |
Interstate Transportation and Storage [Member] | |||
Goodwill, Beginning Balance | 1,195 | 1,884 | |
Goodwill acquired | 0 | 0 | |
Goodwill impairment | 0 | ||
Goodwill, Written off Related to Sale of Business Unit | (184) | ||
Other | 0 | ||
Goodwill, Ending Balance | 1,011 | 1,195 | 1,884 |
Midstream [Member] | |||
Goodwill, Beginning Balance | 686 | 688 | |
Goodwill acquired | 451 | 0 | |
Goodwill impairment | 0 | ||
Goodwill, Written off Related to Sale of Business Unit | 0 | ||
Other | (2) | ||
Goodwill, Ending Balance | 767 | 686 | 688 |
Liquids Transportation And Services [Member] | |||
Goodwill, Beginning Balance | 432 | 432 | |
Goodwill acquired | 0 | 0 | |
Goodwill impairment | 0 | 0 | |
Goodwill, Written off Related to Sale of Business Unit | 0 | ||
Other | 0 | ||
Goodwill, Ending Balance | 432 | 432 | 432 |
Retail Marketing [Member] | |||
Goodwill, Beginning Balance | 1,445 | 1,272 | |
Goodwill acquired | 1,862 | 156 | |
Goodwill impairment | 0 | 0 | |
Goodwill, Written off Related to Sale of Business Unit | 0 | ||
Other | 17 | ||
Goodwill, Ending Balance | 3,307 | 1,445 | 1,272 |
Investment in Sunoco Logistics [Member] | |||
Goodwill, Beginning Balance | 1,346 | 1,368 | |
Goodwill acquired | 12 | 0 | |
Goodwill impairment | 0 | 0 | |
Goodwill, Written off Related to Sale of Business Unit | 0 | ||
Other | (22) | ||
Goodwill, Ending Balance | 1,358 | 1,346 | 1,368 |
Other Segments [Member] | |||
Goodwill, Beginning Balance | 742 | 742 | |
Goodwill acquired | 15 | 0 | |
Goodwill impairment | 0 | 0 | |
Goodwill, Written off Related to Sale of Business Unit | 0 | ||
Other | 0 | ||
Goodwill, Ending Balance | $ 757 | $ 742 | $ 742 |
Estimates, Significant Accoun49
Estimates, Significant Accounting Policies and Balance Sheet Detials (Intangible assets) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Customer relationships, contracts and agreements (3 to 46 years) [Member] | |||
Gross Carrying Amount | $ 5,067 | $ 2,113 | |
Accumulated Amortization | (464) | (256) | |
Patents (9 years) [Member] | |||
Gross Carrying Amount | 48 | 48 | |
Accumulated Amortization | (11) | (6) | |
Trade Names (15 years) [Member] | |||
Gross Carrying Amount | 556 | 66 | |
Accumulated Amortization | (15) | (12) | |
Other (1 to 15 years) [Member] | |||
Gross Carrying Amount | 36 | 7 | |
Accumulated Amortization | (7) | (4) | |
Total Amortizable Intangible Assets [Member] | |||
Gross Carrying Amount | 5,707 | 2,234 | |
Accumulated Amortization | (497) | (278) | |
Non-amortizable intangible assets - Trademarks [Member] | |||
Gross Carrying Amount | 316 | 294 | |
Accumulated Amortization | 0 | 0 | |
Total intangible assets [Member] | |||
Gross Carrying Amount | 6,023 | 2,528 | |
Accumulated Amortization | $ (497) | (278) | |
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member] | |||
Useful Lives | 46 years | ||
Maximum [Member] | Patents (9 years) [Member] | |||
Useful Lives | 9 years | ||
Maximum [Member] | Trade Names (15 years) [Member] | |||
Useful Lives | 15 years | ||
Maximum [Member] | Other (10 to 15 years) [Member] | |||
Useful Lives | 15 years | ||
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years) [Member] | |||
Useful Lives | 3 years | ||
Minimum [Member] | Other (10 to 15 years) [Member] | |||
Useful Lives | 1 year | ||
Depreciation And Amortization [Member] | |||
Amortization of Intangible Assets | $ 212 | $ 117 | $ 65 |
Estimates, Significant Accoun50
Estimates, Significant Accounting Policies and Balance Sheet Detials (Estimated aggregate amortization expense) (Details) $ in Millions | Dec. 31, 2014USD ($) |
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL | |
2,015 | $ 263 |
2,016 | 260 |
2,017 | 260 |
2,018 | 259 |
2,019 | $ 256 |
Estimates, Significant Accoun51
Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Non-Current Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Unamortized financing costs (3 to 30 years) | $ 156 | $ 126 |
Regulatory assets | 85 | 86 |
Deferred Costs, Noncurrent | 220 | 144 |
Restricted Cash and Investments, Noncurrent | 177 | 378 |
Other | 148 | 89 |
Total other non-current assets, net | $ 786 | $ 823 |
Minimum [Member] | Financing Costs (3 to 30 years) [Member] | ||
Finite-Lived Intangible Assets, Useful Life, Minimum | 3 years | |
Maximum [Member] | Financing Costs (3 to 30 years) [Member] | ||
Finite-Lived Intangible Assets, Useful Life, Minimum | 30 years |
Estimates, Significant Accoun52
Estimates, Significant Accounting Policies and Balance Sheet Detials (Asset Retirement Obligations) (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
Asset Retirement Obligation | $ 188 | $ 180 |
Interstate Transportation and Storage [Member] | ||
Asset Retirement Obligation | 60 | 55 |
Investment in Sunoco Logistics [Member] | ||
Asset Retirement Obligation | 41 | 41 |
Retail Marketing [Member] | ||
Asset Retirement Obligation | $ 87 | $ 84 |
Estimates, Significant Accoun53
Estimates, Significant Accounting Policies and Balance Sheet Detials (Accrued and Other Current Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
Other Information [Abstract] | ||
Interest payable | $ 382 | $ 332 |
Customer advances and deposits | 103 | 142 |
Accrued Capital Expenditures | 673 | 258 |
Accrued wages and benefits | 233 | 173 |
Taxes payable other than income taxes | 236 | 211 |
Taxes Payable, Current | 54 | 4 |
Deferred Tax Liabilities, Gross, Current | 99 | 119 |
Other | 319 | 395 |
Total accrued and other current liabilities | $ 2,099 | $ 1,634 |
Estimates, Significant Accoun54
Estimates, Significant Accounting Policies and Balance Sheet Detials (Fair value) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Liabilities, at Fair Value | $ 749 | |
Fair Value, Measured on Recurring Basis, Gain (Loss) Included in Earnings | 3 | |
Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Liabilities, at Fair Value | 551 | |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Liabilities, at Fair Value | 182 | |
Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Liabilities, at Fair Value | 16 | |
Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Interest Rate Derivative Assets, at Fair Value | 3 | $ 47 |
Price Risk Derivative Assets, at Fair Value | 745 | 231 |
Assets, Fair Value Disclosure | 748 | 278 |
Interest Rate Derivative Liabilities, at Fair Value | 155 | 95 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | 16 | 19 |
Price Risk Derivative Liabilities, at Fair Value | (578) | 233 |
Liabilities, Fair Value Disclosure, Recurring | 347 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Interest Rate Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Assets, at Fair Value | 632 | 217 |
Assets, Fair Value Disclosure | 632 | 217 |
Interest Rate Derivative Liabilities, at Fair Value | 0 | 0 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | (551) | 215 |
Liabilities, Fair Value Disclosure, Recurring | 215 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Interest Rate Derivative Assets, at Fair Value | 3 | 47 |
Price Risk Derivative Assets, at Fair Value | 113 | 14 |
Assets, Fair Value Disclosure | 116 | 61 |
Interest Rate Derivative Liabilities, at Fair Value | 155 | 95 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | (27) | 18 |
Liabilities, Fair Value Disclosure, Recurring | 113 | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Interest Rate Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Assets, Fair Value Disclosure | 0 | 0 |
Interest Rate Derivative Liabilities, at Fair Value | 0 | 0 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | 16 | 19 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value | 19 | |
Forward Swaps [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 36 | |
Forward Swaps [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Forward Swaps [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 36 | |
Forward Swaps [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 3 | 3 |
Price Risk Derivative Liabilities, at Fair Value | (4) | (1) |
Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 3 | 3 |
Price Risk Derivative Liabilities, at Fair Value | (4) | (1) |
Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 69 | 7 |
Price Risk Derivative Liabilities, at Fair Value | 32 | 9 |
Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 46 | 5 |
Price Risk Derivative Liabilities, at Fair Value | 32 | 5 |
Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 23 | 2 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 4 |
Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Forward Swaps [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 5 | |
Price Risk Derivative Liabilities, at Fair Value | (7) | (5) |
Forward Swaps [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 5 | |
Price Risk Derivative Liabilities, at Fair Value | (7) | (5) |
Forward Swaps [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Forward Swaps [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 4 | |
Price Risk Derivative Liabilities, at Fair Value | (2) | |
Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 4 | |
Price Risk Derivative Liabilities, at Fair Value | (2) | |
Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 21 | |
Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 21 | |
Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 19 | 5 |
Price Risk Derivative Liabilities, at Fair Value | 18 | 4 |
Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 19 | 5 |
Price Risk Derivative Liabilities, at Fair Value | 18 | 4 |
Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 26 | 8 |
Price Risk Derivative Liabilities, at Fair Value | 25 | 6 |
Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 1 | 1 |
Price Risk Derivative Liabilities, at Fair Value | 2 | 0 |
Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 25 | 7 |
Price Risk Derivative Liabilities, at Fair Value | 23 | 6 |
Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 566 | 203 |
Price Risk Derivative Liabilities, at Fair Value | 490 | 206 |
Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 541 | 201 |
Price Risk Derivative Liabilities, at Fair Value | 490 | 201 |
Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 25 | 2 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 5 |
Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Condensate Forward Swaps [Member] | Commodity [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Embedded Derivative, Fair Value of Embedded Derivative Liability | (1) | |
Condensate Forward Swaps [Member] | Commodity [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Embedded Derivative, Fair Value of Embedded Derivative Liability | 0 | |
Condensate Forward Swaps [Member] | Commodity [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Embedded Derivative, Fair Value of Embedded Derivative Liability | (1) | |
Condensate Forward Swaps [Member] | Commodity [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Embedded Derivative, Fair Value of Embedded Derivative Liability | 0 | |
Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Price Risk Derivative Assets, at Fair Value | $ 0 | |
Forward Physical Swaps [Member] | Commodity [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Trading Liabilities, Fair Value Disclosure | 1 | |
Forward Physical Swaps [Member] | Commodity [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Trading Liabilities, Fair Value Disclosure | 0 | |
Forward Physical Swaps [Member] | Commodity [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Trading Liabilities, Fair Value Disclosure | (1) | |
Forward Physical Swaps [Member] | Commodity [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Trading Liabilities, Fair Value Disclosure | $ 0 |
Estimates, Significant Accoun55
Estimates, Significant Accounting Policies and Balance Sheet Detials (Fair Value Inputs) (Details) | Dec. 31, 2014 |
Fair Value Disclosures [Abstract] | |
Fair Value Embedde Derivatives, Significant Unobservable Input, Credit Spread | 4.76% |
Fair Value, Embedded Derivatives, Significant Unobservable Input, Volatility | 35.80% |
Estimates, Significant Accoun56
Estimates, Significant Accounting Policies and Balance Sheet Detials (Costs and expenses) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Goodwill impairment | $ 370 | $ 689 | $ 0 |
Retail Marketing [Member] | |||
Goodwill impairment | 0 | 0 | |
Excise Taxes Collected | $ 2,460 | $ 2,220 | $ 573 |
Acquisitions and Divestitures57
Acquisitions and Divestitures (Regency Merger) (Details) - USD ($) $ in Millions | Mar. 31, 2012 | Apr. 30, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 31, 2015 | Oct. 05, 2012 |
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 2,200,000 | ||||||||||||||
Number of Regency Common Units to be Issued in Acquisition Per Share | 1.02 | ||||||||||||||
Revenues | $ 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | $ 12,607 | $ 12,486 | $ 12,063 | $ 11,179 | $ 55,475 | $ 48,335 | $ 16,964 | ||||
Net income | (245) | $ 513 | $ 548 | $ 483 | (482) | $ 415 | $ 411 | $ 402 | 1,299 | 746 | 1,645 | ||||
Asset Retirement Obligation | $ 188 | $ 180 | 188 | 180 | |||||||||||
Regency Merger [Member] | |||||||||||||||
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 | ||||||||||||||
Pending Merger [Member] | Regency Merger [Member] | |||||||||||||||
Business Acquisition, Number Of Share Received In Exchange Of Each Share | 0.4124 | ||||||||||||||
Regency | |||||||||||||||
Revenues | 4,840 | 2,242 | 1,309 | ||||||||||||
Net income | $ (142) | $ 64 | $ 48 | ||||||||||||
Incentive Distribution Rights | 100.00% | ||||||||||||||
First year post closing [Member] | Regency Merger [Member] | |||||||||||||||
IDR Subsidies | $ 80 | ||||||||||||||
Four years post closing [Member] | Regency Merger [Member] | |||||||||||||||
IDR Subsidies | $ 60 |
Acquisitions and Divestitures58
Acquisitions and Divestitures (2014 Narrative) (Details) $ / shares in Units, $ in Millions | Mar. 31, 2012shares | Oct. 31, 2014USD ($)shares | Aug. 31, 2014USD ($)shares | Feb. 28, 2014USD ($)shares | Dec. 31, 2013USD ($) | Apr. 30, 2013USD ($)shares | Dec. 31, 2014USD ($)shares | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Sep. 30, 2013USD ($) | Jun. 30, 2013USD ($) | Mar. 31, 2013USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2014USD ($)shares | Dec. 31, 2013USD ($)shares | Dec. 31, 2012USD ($)shares | Oct. 01, 2014 | Aug. 29, 2014USD ($) | Mar. 21, 2014$ / shares | Jun. 24, 2013 | Oct. 05, 2012 |
Business Acquisition [Line Items] | |||||||||||||||||||||||
Revenues | $ 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | $ 12,607 | $ 12,486 | $ 12,063 | $ 11,179 | $ 55,475 | $ 48,335 | $ 16,964 | ||||||||||||
Net income | $ (245) | $ 513 | $ 548 | $ 483 | (482) | $ 415 | $ 411 | $ 402 | 1,299 | 746 | 1,645 | ||||||||||||
Partners' Capital Account, Sale of Units | 1,382 | 1,611 | 791 | ||||||||||||||||||||
Goodwill, Written off Related to Sale of Business Unit | (184) | ||||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 75 | ||||||||||||||||||||||
Cash (paid) received from all other acquisitions | $ (472) | (405) | $ 531 | ||||||||||||||||||||
Debt instrument interest rate | 4.50% | 4.50% | |||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 2,200,000 | ||||||||||||||||||||||
Guarantor Obligations, Current Carrying Value | $ 600 | $ 600 | |||||||||||||||||||||
Number of Regency Common Units to be Issued in Acquisition Per Share | shares | 1.02 | ||||||||||||||||||||||
Asset Retirement Obligation | $ 180 | 188 | 180 | $ 188 | $ 180 | ||||||||||||||||||
Susser Merger [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 1,800 | ||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 875 | ||||||||||||||||||||||
Number of Stores | 630 | ||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 15,800,000 | 0 | 0 | 0 | |||||||||||||||||||
MACS Transaction [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 768 | ||||||||||||||||||||||
Lake Charles LNG Transaction [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Partners' Capital Account, Units, Redeemed | shares | 18,700,000 | (18,700,000) | 0 | 0 | |||||||||||||||||||
Goodwill, Written off Related to Sale of Business Unit | $ 184 | ||||||||||||||||||||||
Indefinite-lived Intangible Assets, Written off Related to Sale of Business Unit | $ 50 | ||||||||||||||||||||||
SUGS Contribution [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 463 | ||||||||||||||||||||||
Cash (paid) received from all other acquisitions | 30 | ||||||||||||||||||||||
ETP Holdco Transaction | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 1,400 | ||||||||||||||||||||||
ETP Holdco Transaction | Common Units | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 49,500,000 | ||||||||||||||||||||||
Sunoco LP [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 556 | ||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 4,000,000 | 11,000,000 | |||||||||||||||||||||
PVR Acquisition [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Revenues | $ 956 | ||||||||||||||||||||||
Net income | 166 | ||||||||||||||||||||||
Eagle Rock Midstream Acquisition [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Revenues | 903 | ||||||||||||||||||||||
Net income | 30 | ||||||||||||||||||||||
New England Gas Company [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Noncash or Part Noncash Divestiture, Amount of Consideration Received | 20 | ||||||||||||||||||||||
Sunoco LP [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Partners' Capital Account, Sale of Units | $ 405 | ||||||||||||||||||||||
Partners' Capital Account, Units, Sale of Units | shares | 9,100,000 | ||||||||||||||||||||||
Proceeds from Issuance of Common Stock | $ 213 | ||||||||||||||||||||||
ETP [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Revenues | 51,158 | $ 46,339 | $ 15,702 | ||||||||||||||||||||
Net income | 1,553 | 767 | 1,647 | ||||||||||||||||||||
Regency | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Revenues | 4,840 | 2,242 | 1,309 | ||||||||||||||||||||
Net income | (142) | 64 | $ 48 | ||||||||||||||||||||
Incentive Distribution Rights | 100.00% | ||||||||||||||||||||||
Regency | PVR Acquisition [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Payments to Acquire Businesses, Gross | 36 | ||||||||||||||||||||||
Business Combination, Consideration Transferred | 5,700 | ||||||||||||||||||||||
Business Acquisition, Share Price | $ / shares | $ 27.82 | ||||||||||||||||||||||
Noncash or Part Noncash Divestiture, Amount of Consideration Received | $ 1,800 | ||||||||||||||||||||||
Stock Issued During Period, Shares, Acquisitions | shares | 140,400,000 | ||||||||||||||||||||||
Regency | Eagle Rock Midstream Acquisition [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 1,300 | ||||||||||||||||||||||
Proceeds from Issuance of Common Stock | $ 400 | ||||||||||||||||||||||
Stock Issued During Period, Shares, Acquisitions | shares | 8,200,000 | ||||||||||||||||||||||
Regency | Hoover Midstream Acquisition [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 184 | ||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 293 | ||||||||||||||||||||||
Stock Issued During Period, Shares, Acquisitions | shares | 4,000,000 | ||||||||||||||||||||||
Asset Retirement Obligation | $ 2 | $ 2 | |||||||||||||||||||||
Susser [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Acquisition Related Costs | 25 | ||||||||||||||||||||||
Revenues | 2,320 | ||||||||||||||||||||||
Net income | $ 105 | ||||||||||||||||||||||
Incentive Distribution Rights | 100.00% | ||||||||||||||||||||||
Common Units | Regency | SUGS Contribution [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 31,400,000 | ||||||||||||||||||||||
Class F Units [Member] | Regency | SUGS Contribution [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 6,300,000 | ||||||||||||||||||||||
Susser Merger [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Total current assets | $ 446 | ||||||||||||||||||||||
Property, plant and equipment | 1,069 | ||||||||||||||||||||||
Goodwill1 | 1,734 | ||||||||||||||||||||||
Intangible assets | 611 | ||||||||||||||||||||||
Other non-current assets | 17 | ||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 3,877 | ||||||||||||||||||||||
Total current liabilities | 377 | ||||||||||||||||||||||
Long-term debt, less current maturities | 564 | ||||||||||||||||||||||
Deferred income taxes | 488 | ||||||||||||||||||||||
Other non-current liabilities | 39 | ||||||||||||||||||||||
Noncontrolling interest | 626 | ||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 2,094 | ||||||||||||||||||||||
Total consideration | 1,783 | ||||||||||||||||||||||
Cash received | 67 | ||||||||||||||||||||||
Total consideration, net of cash received | $ 1,716 | ||||||||||||||||||||||
Company-operated [Member] | MACS Transaction [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Number of Stores | 110 | ||||||||||||||||||||||
Dealer-operated [Member] | MACS Transaction [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Number of Stores | 200 | ||||||||||||||||||||||
8.375% Senior Notes due June 1, 2019 [Member] | Regency | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Debt instrument interest rate | 8.375% | 8.375% | |||||||||||||||||||||
Senior Notes | $ 0 | $ 499 | $ 0 | $ 499 | $ 0 | ||||||||||||||||||
7.60% Senior Notes due February 1, 2024 | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Debt instrument interest rate | 7.60% | ||||||||||||||||||||||
8.25% Senior Notes due November 14, 2029 | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Debt instrument interest rate | 8.25% |
Acquisitions and Divestitures59
Acquisitions and Divestitures (2013 Narrative) (Details) - USD ($) shares in Millions, $ in Millions | Mar. 31, 2012 | Jan. 12, 2012 | Dec. 31, 2013 | Sep. 30, 2013 | Apr. 30, 2013 | Oct. 31, 2012 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Jun. 30, 2012 | Sep. 30, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 05, 2012 | Mar. 25, 2012 | Dec. 31, 2011 | |
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 2.2 | ||||||||||||||||||||||
Revenues | $ 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | $ 12,607 | $ 12,486 | $ 12,063 | $ 11,179 | $ 55,475 | $ 48,335 | $ 16,964 | ||||||||||||
Net Income (Loss) Attributable to Parent | $ 1,336 | $ 456 | $ 1,569 | ||||||||||||||||||||
Partners' Capital Account, Units | 333.8 | 355.5 | 333.8 | 355.5 | 333.8 | 301.5 | 225.5 | ||||||||||||||||
SUGS Contribution [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 463 | ||||||||||||||||||||||
Southern Union Merger [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Acquisition Units Acquired | 57 | ||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 3,010 | ||||||||||||||||||||||
Business Combination, Acquisition Related Costs | $ 38 | ||||||||||||||||||||||
Revenues | 1,260 | ||||||||||||||||||||||
Net Income (Loss) Attributable to Parent | 39 | ||||||||||||||||||||||
Cash received | [1] | $ 37 | |||||||||||||||||||||
Citrus Merger [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Consideration Transferred | 2,000 | ||||||||||||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 1,900 | ||||||||||||||||||||||
Sunoco Merger | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Acquisition Units Acquired | 55 | ||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 2,600 | ||||||||||||||||||||||
Business Combination, Acquisition Related Costs | 28 | ||||||||||||||||||||||
Revenues | 5,930 | ||||||||||||||||||||||
Net Income (Loss) Attributable to Parent | 14 | ||||||||||||||||||||||
Cash received | [2] | $ 2,714 | |||||||||||||||||||||
ETP Holdco Transaction | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Consideration Transferred | 1,400 | ||||||||||||||||||||||
Estimated Closing Adjustments | $ 68 | ||||||||||||||||||||||
Relinquishment of Rights of Incentive Distributions, Percentage | 50.00% | ||||||||||||||||||||||
ETP Holdco Transaction | Common Units | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 49.5 | ||||||||||||||||||||||
AmeriGas [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Contingent Consideration, Liability | $ 1,550 | 1,550 | |||||||||||||||||||||
AmeriGas [Member] | Propane Cylinder Exchange Business [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Proceeds from Divestiture of Businesses | $ 43 | ||||||||||||||||||||||
Regency | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Revenues | 4,840 | $ 2,242 | $ 1,309 | ||||||||||||||||||||
Incentive Distribution Rights | 100.00% | ||||||||||||||||||||||
ETP [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Revenues | $ 51,158 | $ 46,339 | $ 15,702 | ||||||||||||||||||||
Equity interest in Holdco | 40.00% | ||||||||||||||||||||||
ETP [Member] | ETP Holdco Transaction | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Equity interest in Holdco | 100.00% | 100.00% | |||||||||||||||||||||
Sunoco Logistics [Member] | Sunoco Merger | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Revenues | $ 3,110 | ||||||||||||||||||||||
Net Income (Loss) Attributable to Parent | $ 145 | ||||||||||||||||||||||
Parent Company [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Equity interest in Holdco | 60.00% | ||||||||||||||||||||||
Parent Company [Member] | ETP Holdco Transaction | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Equity interest in Holdco | 60.00% | ||||||||||||||||||||||
Sunoco [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
General Partner Interest | 2.00% | ||||||||||||||||||||||
Incentive Distribution Rights | 100.00% | ||||||||||||||||||||||
Percent of total equity ownership of a subsidiary | 32.00% | ||||||||||||||||||||||
Sunoco [Member] | Class F Units [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Partners' Capital Account, Units | 40 | 40 | |||||||||||||||||||||
Sunoco [Member] | ETP Holdco Transaction | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Cash received | $ 2,000 | ||||||||||||||||||||||
Carlyle Group [Member] | PES | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Subsidiary Interest in Joint Venture | 67.00% | 67.00% | |||||||||||||||||||||
Sunoco [Member] | PES | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Subsidiary Interest in Joint Venture | 33.00% | 33.00% | |||||||||||||||||||||
Retained Interest, Fair Value Disclosure | $ 75 | $ 75 | |||||||||||||||||||||
AmeriGas [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 29.6 | ||||||||||||||||||||||
Proceeds from Divestiture of Businesses | $ 1,460 | ||||||||||||||||||||||
Noncash or Part Noncash Divestiture, Amount of Consideration Received | 71 | ||||||||||||||||||||||
Business Combination, Contingent Consideration, Liability | 1,500 | ||||||||||||||||||||||
Debt Of Subsidiary Guaranteed | $ 1,500 | ||||||||||||||||||||||
Missouri Gas Energy [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Proceeds from Divestiture of Businesses | $ 975 | ||||||||||||||||||||||
New England Gas Company [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Proceeds from Divestiture of Businesses | $ 40 | ||||||||||||||||||||||
Noncash or Part Noncash Divestiture, Amount of Consideration Received | $ 20 | ||||||||||||||||||||||
Canyon Disposal [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | $ 132 | ||||||||||||||||||||||
Canyon Disposal [Member] | Canyon [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 207 | ||||||||||||||||||||||
Common Units | Regency | SUGS Contribution [Member] | |||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 31.4 | ||||||||||||||||||||||
[1] | Includes ETP’s acquisition of Citrus. | ||||||||||||||||||||||
[2] | Includes amounts recorded with respect to Sunoco Logistics. |
Acquisitions and Divestitures60
Acquisitions and Divestitures (2012 Narrative) (Details) - USD ($) shares in Millions, $ in Millions | Mar. 31, 2012 | Jan. 12, 2012 | Apr. 30, 2013 | Jun. 30, 2012 | Dec. 31, 2015 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 05, 2012 | Dec. 31, 2011 |
Business Acquisition [Line Items] | ||||||||||||||
Relinquishment of Incentive Distributions | $ 56 | $ 95 | $ 105 | $ 128 | $ 137 | |||||||||
Partners' Capital Account, Units | 301.5 | 355.5 | 333.8 | 225.5 | ||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 2.2 | |||||||||||||
ETP Holdco Transaction | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Business Combination, Consideration Transferred | $ 1,400 | |||||||||||||
ETP Holdco Transaction | Class G Units | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Relinquishment of Incentive Distributions | $ 210 | |||||||||||||
Partners' Capital Account, Units | 90.7 | |||||||||||||
SUGS Contribution [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Business Combination, Consideration Transferred | $ 463 | |||||||||||||
AmeriGas [Member] | Propane Cylinder Exchange Business [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Proceeds from Divestiture of Businesses | $ 43 | |||||||||||||
Parent Company [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Equity interest in Holdco | 60.00% | |||||||||||||
Parent Company [Member] | ETP Holdco Transaction | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Equity interest in Holdco | 60.00% | |||||||||||||
Sunoco [Member] | PES | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Subsidiary Interest in Joint Venture | 33.00% | |||||||||||||
AmeriGas [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Proceeds from Divestiture of Businesses | $ 1,460 | |||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 29.6 | |||||||||||||
Common Units | Regency | SUGS Contribution [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 31.4 |
Acquisitions and Divestitures61
Acquisitions and Divestitures (PVR PPA) (Details) - PVR Acquisition [Member] - USD ($) $ in Millions | Aug. 29, 2014 | Mar. 21, 2014 |
Business Acquisition [Line Items] | ||
Total current assets | $ 149 | |
Property, plant and equipment | 2,716 | |
Investments in unconsolidated affiliates | 62 | |
Intangible assets | 2,717 | |
Goodwill1 | $ 370 | 370 |
Other non-current assets | 18 | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 6,032 | |
Total current liabilities | 168 | |
Long-term debt, less current maturities | 1,788 | |
Business Combination, Purchase Price Allocation, Premium on Long Term Debt | 99 | |
Other non-current liabilities | 30 | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 2,085 | |
Total consideration | $ 3,947 |
Acquisitions and Divestitures62
Acquisitions and Divestitures (Eagle Rock PPA) (Details) - Eagle Rock Midstream Acquisition [Member] $ in Millions | Jul. 01, 2014USD ($) |
Business Acquisition [Line Items] | |
Total current assets | $ 113 |
Property, plant and equipment | 1,295 |
Goodwill1 | 59 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 1,467 |
Total current liabilities | 116 |
Long-term debt, less current maturities | 499 |
Other non-current liabilities | 11 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 626 |
Total consideration | $ 841 |
Acquisitions and Divestitures63
Acquisitions and Divestitures (Sunoco and Southern Union PPA) (Details) - USD ($) $ in Millions | Aug. 29, 2014 | Oct. 05, 2012 | Mar. 25, 2012 | |
Sunoco Merger [Member] | ||||
Business Acquisition [Line Items] | ||||
Total current assets | [1] | $ 7,312 | ||
Property, plant and equipment | [1] | 6,686 | ||
Goodwill | [1] | 2,641 | ||
Intangible Assets Acquired | [1] | 1,361 | ||
Investments in unconsolidated affiliates | [1] | 240 | ||
Note receivable | [1] | 821 | ||
Other non-current assets | [1] | 128 | ||
Total assets acquired (excluding cash) | [1] | 19,189 | ||
Total current liabilities | [1] | 4,424 | ||
Long-term debt, less current maturities | [1] | 2,879 | ||
Deferred income taxes | [1] | 1,762 | ||
Other non-current liabilities | [1] | 769 | ||
Noncontrolling interest | [1] | 3,580 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | [1] | 13,414 | ||
Business Combination, Cost of Acquired Entity, Purchase Price | [1] | 5,775 | ||
Total consideration, net of cash received | [1] | 3,061 | ||
Cash received | [1] | $ 2,714 | ||
Southern Union Merger [Member] | ||||
Business Acquisition [Line Items] | ||||
Total current assets | [2] | $ 556 | ||
Property, plant and equipment | [2] | 6,242 | ||
Goodwill | [2] | 2,497 | ||
Intangible Assets Acquired | [2] | 55 | ||
Investments in unconsolidated affiliates | [2] | 2,023 | ||
Note receivable | [2] | 0 | ||
Other non-current assets | [2] | 163 | ||
Total assets acquired (excluding cash) | [2] | 11,536 | ||
Total current liabilities | [2] | 1,348 | ||
Long-term debt, less current maturities | [2] | 3,120 | ||
Deferred income taxes | [2] | 1,419 | ||
Other non-current liabilities | [2] | 284 | ||
Noncontrolling interest | [2] | 0 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | [2] | 6,171 | ||
Business Combination, Cost of Acquired Entity, Purchase Price | [2] | 5,365 | ||
Total consideration, net of cash received | [2] | 5,328 | ||
Cash received | [2] | $ 37 | ||
Susser Merger [Member] | ||||
Business Acquisition [Line Items] | ||||
Total current assets | $ 446 | |||
Property, plant and equipment | 1,069 | |||
Goodwill | 1,734 | |||
Intangible Assets Acquired | 611 | |||
Other non-current assets | 17 | |||
Total assets acquired (excluding cash) | 3,877 | |||
Total current liabilities | 377 | |||
Long-term debt, less current maturities | 564 | |||
Deferred income taxes | 488 | |||
Other non-current liabilities | 39 | |||
Noncontrolling interest | 626 | |||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 2,094 | |||
Business Combination, Cost of Acquired Entity, Purchase Price | 1,783 | |||
Total consideration, net of cash received | 1,716 | |||
Cash received | $ 67 | |||
[1] | Includes amounts recorded with respect to Sunoco Logistics. | |||
[2] | Includes ETP’s acquisition of Citrus. |
Acquisitions and Divestitures64
Acquisitions and Divestitures (Pro forma Results of Operations) (Details) - USD ($) $ / shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Business Acquisition [Line Items] | |||
Revenues | $ 56,301 | $ 50,473 | $ 40,397 |
Net Income | 1,151 | 532 | 1,240 |
Business acquisition pro forma net income (loss) attributable to partners | $ 1,323 | $ 423 | $ 817 |
Basic net income (loss) per Limited Partner unit | $ 0 | $ 0 | $ 0 |
Diluted net income (loss) per Limited Partner unit | $ 0 | $ 0 | $ 0 |
Acquisitions and Divestitures65
Acquisitions and Divestitures (Discontinued operations) (Details) - Distribution [Member] - USD ($) $ in Millions | 9 Months Ended | 12 Months Ended |
Dec. 31, 2012 | Dec. 31, 2013 | |
Disposal Group, Including Discontinued Operation, Revenue | $ 324 | $ 415 |
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax | $ 43 | $ 65 |
Acquisitions and Divestitures66
Acquisitions and Divestitures (2015 Narrative) (Details) - Scenario, Unspecified [Domain] shares in Millions, $ in Millions, gallons in Billions | 1 Months Ended | 6 Months Ended | 12 Months Ended | ||
Apr. 30, 2015USD ($)shares | Jun. 30, 2015USD ($)gallonsshares | Dec. 31, 2014shares | Dec. 31, 2013shares | Dec. 31, 2012shares | |
Stock Repurchased During Period, Shares | shares | 0 | (0.4) | 0 | ||
Sunoco LP Exchange [Member] | |||||
Stock Repurchased During Period, Shares | shares | 21 | ||||
IDR Subsidies | $ 35 | ||||
Term of IDR Subsidy | |||||
Dropdown of Susser [Member] | |||||
Business Combination, Consideration Transferred | $ 967 | $ 1,930 | |||
Payments to Acquire Businesses, Gross | 967 | ||||
Dropdown of Sunoco LLC Interest [Member] | |||||
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage | 31.58% | ||||
Business Combination, Consideration Transferred | $ 816 | ||||
Gallons of motor fuel distributed | gallons | 5.3 | ||||
Payments to Acquire Businesses, Gross | $ 775 | ||||
Equity Issued in Business Combination, Fair Value Disclosure | $ 41 | ||||
Regency Merger [Member] | |||||
Preferred Units, Issued | shares | 1.9 | ||||
IDR Subsidies | $ 320 | ||||
Sunoco GP [Member] | Sunoco LP Exchange [Member] | |||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||
Sunoco LP [Member] | |||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 42.80% | ||||
Sunoco LP [Member] | Dropdown of Susser [Member] | |||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 22 | ||||
Susser [Member] | |||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||
Susser [Member] | Dropdown of Susser [Member] | |||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||
Susser [Member] | Sunoco LP [Member] | Dropdown of Susser [Member] | |||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 11 | ||||
ETP [Member] | Sunoco LP [Member] | Dropdown of Susser [Member] | |||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 11 |
Acquisitions and Divestitures C
Acquisitions and Divestitures Combined Table (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Revenues | $ 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | $ 12,607 | $ 12,486 | $ 12,063 | $ 11,179 | $ 55,475 | $ 48,335 | $ 16,964 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $ (245) | $ 513 | $ 548 | $ 483 | $ (482) | $ 415 | $ 411 | $ 402 | 1,299 | 746 | 1,645 |
ETP [Member] | |||||||||||
Revenues | 51,158 | 46,339 | 15,702 | ||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 1,553 | 767 | 1,647 | ||||||||
Regency | |||||||||||
Revenues | 4,840 | 2,242 | 1,309 | ||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | (142) | 64 | 48 | ||||||||
Adjustments And Eliminations [Member] | |||||||||||
Revenues | (523) | (246) | (47) | ||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $ (112) | $ (85) | $ (50) |
Investments in Unconsolidated68
Investments in Unconsolidated Affiliates (Narrative) (Details) - USD ($) shares in Millions, $ in Millions | Mar. 31, 2012 | Jan. 12, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Schedule of Investments [Line Items] | |||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | $ 3,760 | $ 4,050 | $ 4,768 | ||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 2.2 | ||||
GOODWILL | $ 7,642 | $ 5,856 | 6,396 | ||
AmeriGas common units sold by ETP | (18.9) | (7.5) | |||
Cash proceeds from the sale of AmeriGas common units | $ 814 | $ 346 | $ 0 | ||
RIGS Haynesville Partnership Co. [Member] | |||||
Schedule of Investments [Line Items] | |||||
Equity Method Investment, Ownership Percentage | 49.99% | ||||
FGT | |||||
Schedule of Investments [Line Items] | |||||
Percentage Ownership Operating Facility | 100.00% | ||||
AmeriGas [Member] | |||||
Schedule of Investments [Line Items] | |||||
Cash proceeds from the sale of AmeriGas common units | $ 814 | 346 | |||
Investment Owned, Balance, Shares | 3.1 | ||||
SUG [Member] | |||||
Schedule of Investments [Line Items] | |||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||
Payments to Acquire Businesses, Gross | $ 1,900 | ||||
Business acquisition, cost of acquired entity, equity interest issued and issuable | $ 105 | ||||
Citrus Corp [Member] | |||||
Schedule of Investments [Line Items] | |||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | $ 2,000 | ||||
GOODWILL | $ 1,030 | ||||
Midcontinent Express Pipeline, LLC [Member] | |||||
Schedule of Investments [Line Items] | |||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||
Citrus [Member] | |||||
Schedule of Investments [Line Items] | |||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||
FEP [Member] | |||||
Schedule of Investments [Line Items] | |||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||
Citrus Corp [Member] | |||||
Schedule of Investments [Line Items] | |||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | ||||
RIGS Haynesville Partnership Co. [Member] | Regency | |||||
Schedule of Investments [Line Items] | |||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | $ 422 | 442 | |||
MEP [Member] | Regency | |||||
Schedule of Investments [Line Items] | |||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 695 | 548 | |||
FEP [Member] | ETP [Member] | |||||
Schedule of Investments [Line Items] | |||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 130 | 144 | |||
Citrus [Member] | ETP [Member] | |||||
Schedule of Investments [Line Items] | |||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | $ 1,820 | $ 1,890 | |||
AmeriGas [Member] | |||||
Schedule of Investments [Line Items] | |||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 29.6 |
Investments in Unconsolidated69
Investments in Unconsolidated Affiliates (Table) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Investments in and Advances to Affiliates [Line Items] | |||
Revenue | $ 4,925 | $ 4,695 | $ 4,492 |
Operating income | 1,071 | 1,197 | 863 |
Net income | 577 | 699 | $ 491 |
Current assets | 889 | 1,028 | |
Property, plant and equipment, net | 10,520 | 10,778 | |
Other assets | 2,687 | 2,664 | |
Total assets | 14,096 | 14,470 | |
Current liabilities | 1,983 | 1,039 | |
Non-current liabilities | 7,359 | 8,139 | |
Equity | 4,754 | 5,292 | |
Total liabilities and equity | $ 14,096 | $ 14,470 |
Net Income Per Limited Partne70
Net Income Per Limited Partner Unit (A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Income from continuing operations | $ 1,235 | $ 713 | $ 1,754 |
Less: Income from continuing operations attributable to noncontrolling interest | 116 | 239 | 20 |
Net Income (Loss) Allocated to Predecessor Equity | (153) | 35 | 39 |
Income from continuing operations, net of noncontrolling interest and predecessor income (loss) | 1,272 | 439 | 1,695 |
General Partner’s interest in income from continuing operations | 513 | 505 | 463 |
Class H Unitholder’s interest in income from continuing operations | 217 | 48 | 0 |
Common Unitholders’ interest in income (loss) from continuing operations | 542 | (66) | 1,232 |
Additional earnings allocated (to) from General Partner | (4) | (2) | 1 |
Distributions on employee unit awards, net of allocation to General Partner | (13) | (10) | (9) |
Income (loss) from continuing operations available to Common Unitholders | $ 525 | $ (78) | $ 1,224 |
Weighted average Common Units – basic | 331.5 | 343.4 | 248.3 |
Basic income (loss) from continuing operations per Common Unit | $ 1.58 | $ (0.23) | $ 4.93 |
Dilutive effect of unvested Unit Awards | 1.3 | 0 | 0.7 |
Weighted average Common Units, assuming dilutive effect of unvested Unit Awards | 332.8 | 343.4 | 249 |
Diluted income (loss) from continuing operations per Common Unit | $ 1.58 | $ (0.23) | $ 4.91 |
Basic income (loss) from discontinued operations per Common Unit | 0.19 | 0.05 | (0.50) |
Diluted income (loss) from discontinued operations per Common Unit | $ 0.19 | $ 0.05 | $ (0.50) |
Class H Units | |||
Class H Unitholder’s interest in income from continuing operations | $ 0 | $ 0 |
Debt Obligations (Narrative) (D
Debt Obligations (Narrative) (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||||||||
Jul. 31, 2014USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2013USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2012USD ($) | Jul. 31, 2015USD ($) | Apr. 30, 2015USD ($) | Jul. 01, 2014USD ($) | Apr. 30, 2014USD ($) | Jun. 24, 2013 | Oct. 05, 2012USD ($) | |
Unamortized Net Premiums And Fair Value Adjustments | $ 280 | |||||||||||||
Long-term Debt | $ 20,398 | 25,981 | $ 20,398 | |||||||||||
Noncash or Part Noncash Acquisition, Debt Assumed | $ 1,887 | 0 | $ 0 | |||||||||||
Senior note interest rate | 4.50% | |||||||||||||
Proceeds from borrowings | $ 15,354 | 10,854 | 10,762 | |||||||||||
Repayments of Long-term Debt | $ 12,702 | 8,700 | $ 8,685 | |||||||||||
Debt Instrument, Covenant Description | 0.66 | |||||||||||||
Regency Credit Facility [Member] | ||||||||||||||
Line Of Credit Facility Fronting Fee Percentage | 0.20% | |||||||||||||
Debt, Weighted Average Interest Rate | 2.17% | |||||||||||||
Amount available for future borrowings under the revolving credit facitlity | $ 473 | |||||||||||||
Letters of credit outstanding, amount | 23 | |||||||||||||
Line of Credit Facility, Current Borrowing Capacity | 2,000 | |||||||||||||
Maximum revolving credit capacity | 500 | |||||||||||||
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015(3) | ||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | 35 | |||||||||||||
Sunoco Merger | ||||||||||||||
Senior note principal amount | 715 | $ 965 | ||||||||||||
7.60% Senior Notes due February 1, 2024 | ||||||||||||||
Senior note interest rate | 7.60% | |||||||||||||
8.25% Senior Notes due November 14, 2029 | ||||||||||||||
Senior note interest rate | 8.25% | |||||||||||||
ETP [Member] | ||||||||||||||
Long-term Debt | 11,213 | $ 11,459 | 11,213 | |||||||||||
Proceeds from borrowings | $ 2,980 | $ 2,480 | ||||||||||||
Leverage Ratio Maximum | 5 | |||||||||||||
Maximum Leverage Ratio Permitted | 5.5 | |||||||||||||
ETP [Member] | 2.50% Senior Notes due June 2018 [Member] | ||||||||||||||
Senior note principal amount | $ 650 | $ 650 | ||||||||||||
Senior note interest rate | 2.50% | 2.50% | ||||||||||||
ETP [Member] | 4.15% Senior Notes due October 1, 2020 | ||||||||||||||
Senior note principal amount | $ 350 | $ 350 | ||||||||||||
Senior note interest rate | 4.15% | 4.15% | ||||||||||||
ETP [Member] | 4.75% Senior Notes due January 2026 [Member] | ||||||||||||||
Senior note principal amount | $ 1,000 | $ 1,000 | ||||||||||||
Senior note interest rate | 4.75% | 4.75% | ||||||||||||
ETP [Member] | 6.125% Senior Notes due December 2045 [Member] | ||||||||||||||
Senior note principal amount | $ 1,000 | $ 1,000 | ||||||||||||
Senior note interest rate | 6.125% | 6.125% | ||||||||||||
ETP [Member] | 4.05% Senior Notes due March 2025 [Member] | ||||||||||||||
Senior note principal amount | $ 1,000 | $ 1,000 | ||||||||||||
Senior note interest rate | 4.05% | 4.05% | ||||||||||||
ETP [Member] | 4.90% Senior Notes due March 2035 [Member] | ||||||||||||||
Senior note principal amount | $ 500 | $ 500 | ||||||||||||
Senior note interest rate | 4.90% | 4.90% | ||||||||||||
ETP [Member] | 5.15% Senior Notes due March 2045 [Member] | ||||||||||||||
Senior note principal amount | $ 1,000 | $ 1,000 | ||||||||||||
Senior note interest rate | 5.15% | 5.15% | ||||||||||||
Sunoco Logistics [Member] | ||||||||||||||
Long-term Debt | 2,503 | $ 4,260 | 2,503 | |||||||||||
Maximum Consolidated EBITDA ratio | 5 | |||||||||||||
Adjusted EBITDA Ratio | 3.7 | |||||||||||||
Sunoco Logistics [Member] | Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018 | ||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 2,500 | $ 2,500 | $ 1,500 | |||||||||||
Maximum revolving credit capacity | 2,250 | |||||||||||||
Sunoco LP [Member] | ||||||||||||||
Long-term Debt | 0 | $ 683 | 0 | |||||||||||
Leverage Ratio Maximum | 5.50 | |||||||||||||
Maximum Leverage Ratio Permitted | 6 | |||||||||||||
Debt Instrument, Covenant Description | 50 | |||||||||||||
Sunoco LP [Member] | 6.375% Senior Notes due April 2023 [Member] | ||||||||||||||
Senior note principal amount | $ 800 | |||||||||||||
Senior note interest rate | 6.375% | |||||||||||||
Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member] | ||||||||||||||
Senior note principal amount | $ 600 | |||||||||||||
Senior note interest rate | 5.50% | |||||||||||||
Sunoco LP [Member] | Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019 | ||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 1,250 | |||||||||||||
Maximum revolving credit capacity | 250 | |||||||||||||
Regency | ||||||||||||||
Long-term Debt | $ 3,310 | $ 6,641 | 3,310 | |||||||||||
Maximum Consolidated EBITDA ratio | 5 | |||||||||||||
Minimum Consolidated EBITA To Consolidated Interest Expense | 2.50 | |||||||||||||
Maximum Consolidated Senior Secured Leverage Ratio | 3.25 | |||||||||||||
Regency | Senior Notes due 2018 [Member] | ||||||||||||||
Debt Instrument, Repurchase Amount | $ 621 | |||||||||||||
Debt Instrument, Repurchased Face Amount | $ 600 | |||||||||||||
Regency | 4.5% Senior Notes due November 1, 2023 [Member] | ||||||||||||||
Senior note principal amount | $ 600 | $ 600 | ||||||||||||
Senior note interest rate | 4.50% | 4.50% | ||||||||||||
Regency | 8.375% Senior Notes due June 1, 2019 [Member] | ||||||||||||||
Early Repayment of Senior Debt | $ 499 | |||||||||||||
Senior note interest rate | 8.375% | 8.375% | ||||||||||||
Regency | 8.25% Senior Notes due April 15, 2018 [Member] | ||||||||||||||
Debt Instrument, Repurchase Amount | $ 313 | |||||||||||||
Debt Instrument, Repurchased Face Amount | $ 300 | |||||||||||||
Regency | 8.375% Senior Notes due June 1, 2020 [Member] | ||||||||||||||
Debt Instrument, Repurchase Amount | $ 91 | |||||||||||||
Redemption Premium | $ 8 | |||||||||||||
Debt Instrument, Repurchased Face Amount | $ 83 | |||||||||||||
West Texas Gulf [Member] | ||||||||||||||
Leverage Ratio Maximum | 2 | |||||||||||||
Fixed Charge Coverage Ratio | 1.67 | |||||||||||||
Debt Instrument Covenant Minimum Fixed Charge Coverage Ratio | 1 | |||||||||||||
Leverage Ratio | 0.85 | |||||||||||||
Acquisition Period [Member] | Sunoco Logistics [Member] | ||||||||||||||
Maximum Consolidated EBITDA ratio | 5.5 | |||||||||||||
ETP $2.5 billion Revolving Credit Facility due October 27, 2019 | ||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 2,500 | |||||||||||||
Maximum revolving credit capacity | 3,750 | |||||||||||||
ETP $2.5 billion Revolving Credit Facility due October 27, 2019 | ETP [Member] | ||||||||||||||
Amount available for future borrowings under the revolving credit facitlity | 1,810 | |||||||||||||
Line Of Credit Maturity October 27, 2016 [Member] | ||||||||||||||
Letters of credit outstanding, amount | 121 | |||||||||||||
Revolving Credit Facility [Member] | Regency | ||||||||||||||
Revolving credit facility balance outstanding | $ 510 | 1,504 | 510 | |||||||||||
8.75% Senior Notes due February 15, 2014(2) | Sunoco Logistics [Member] | ||||||||||||||
Senior note principal amount | 175 | $ 0 | 175 | |||||||||||
Senior note interest rate | 8.75% | |||||||||||||
Senior note maturity date | Feb. 15, 2014 | |||||||||||||
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member] | ||||||||||||||
Senior note principal amount | 0 | $ 500 | 0 | |||||||||||
Senior note interest rate | 4.25% | |||||||||||||
Senior note maturity date | Apr. 1, 2024 | |||||||||||||
4.25% Senior Notes due April 1, 2024 | April 2014 Offering [Member] | Sunoco Logistics [Member] | ||||||||||||||
Senior note principal amount | $ 300 | |||||||||||||
Senior note interest rate | 4.25% | |||||||||||||
4.25% Senior Notes due April 1, 2024 | November 2014 Secondary Offering [Member] | Sunoco Logistics [Member] | ||||||||||||||
Senior note principal amount | $ 200 | |||||||||||||
Senior note interest rate | 4.25% | |||||||||||||
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member] | ||||||||||||||
Senior note principal amount | 0 | $ 700 | 0 | |||||||||||
Senior note interest rate | 5.30% | |||||||||||||
Senior note maturity date | Apr. 1, 2044 | |||||||||||||
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member] | ||||||||||||||
Senior note principal amount | 350 | $ 350 | 350 | |||||||||||
Senior note interest rate | 3.45% | |||||||||||||
Senior note maturity date | Jan. 15, 2023 | |||||||||||||
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member] | ||||||||||||||
Senior note principal amount | 350 | $ 350 | 350 | |||||||||||
Senior note interest rate | 4.95% | |||||||||||||
Senior note maturity date | Jan. 15, 2043 | |||||||||||||
Junior Subordinated Debt [Member] | SUG [Member] | ||||||||||||||
Debt Instrument, Description of Variable Rate Basis | three-month LIBOR rate plus 3.0175% | |||||||||||||
Junior Subordinated Debt [Member] | Variable Rate Portion of Debt [Member] | SUG [Member] | ||||||||||||||
Senior note principal amount | $ 54 | |||||||||||||
3.60% Senior Notes due February 1, 2023 | ETP [Member] | ||||||||||||||
Senior note principal amount | 800 | $ 800 | 800 | |||||||||||
Senior note interest rate | 3.60% | |||||||||||||
Senior note maturity date | Feb. 1, 2023 | |||||||||||||
5.15% Senior Notes due February 1, 2043 | ETP [Member] | ||||||||||||||
Senior note principal amount | 450 | $ 450 | 450 | |||||||||||
Senior note interest rate | 5.15% | |||||||||||||
Senior note maturity date | Feb. 1, 2043 | |||||||||||||
ETP $2.5 billion Revolving Credit Facility due October 27, 2019 | ETP [Member] | ||||||||||||||
Senior note maturity date | Oct. 27, 2019 | |||||||||||||
Revolving credit facility balance outstanding | 65 | $ 570 | 65 | |||||||||||
ETP $2.5 billion Revolving Credit Facility due October 27, 2019 | Line Of Credit Maturity October 27, 2016 [Member] | ETP [Member] | ||||||||||||||
Weighted average interest rate on the total amount outstanding | 1.66205% | |||||||||||||
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019 | Sunoco LP [Member] | ||||||||||||||
Revolving credit facility balance outstanding | 0 | $ 683 | 0 | |||||||||||
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member] | ||||||||||||||
Senior note principal amount | 0 | $ 800 | 0 | |||||||||||
Senior note interest rate | 5.35% | |||||||||||||
Senior note maturity date | May 15, 2045 | |||||||||||||
5.875% Senior Notes due March 1, 2022 [Member] | Regency | ||||||||||||||
Senior note principal amount | 0 | $ 900 | 0 | |||||||||||
Senior note interest rate | 5.875% | |||||||||||||
Senior note maturity date | Mar. 1, 2022 | |||||||||||||
8.375% Senior Notes due June 1, 2019 [Member] | Regency | ||||||||||||||
Senior note principal amount | 0 | $ 499 | 0 | |||||||||||
Senior note interest rate | 8.375% | |||||||||||||
Senior note maturity date | Jun. 1, 2019 | |||||||||||||
5.0% Senior Notes due October 1, 2022 [Member] | Regency | ||||||||||||||
Senior note principal amount | $ 0 | $ 700 | $ 0 | |||||||||||
Senior note interest rate | 5.00% | |||||||||||||
Senior note maturity date | Oct. 1, 2022 | |||||||||||||
Federal Funds Effective Rate [Member] | Regency Credit Facility [Member] | ||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | |||||||||||||
LIBOR [Member] | Regency Credit Facility [Member] | ||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | |||||||||||||
Maximum [Member] | Regency Credit Facility [Member] | ||||||||||||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.45% | |||||||||||||
Line Of Credit Participation Fee | 2.50% | |||||||||||||
Maximum [Member] | Base Rate Loans [Member] | Regency Credit Facility [Member] | ||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.50% | |||||||||||||
Maximum [Member] | Eurodollar Loans [Member] | Regency Credit Facility [Member] | ||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 2.50% | |||||||||||||
Minimum [Member] | Regency Credit Facility [Member] | ||||||||||||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.30% | |||||||||||||
Line Of Credit Participation Fee | 1.625% | |||||||||||||
Minimum [Member] | Base Rate Loans [Member] | Regency Credit Facility [Member] | ||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 0.625% | |||||||||||||
Minimum [Member] | Eurodollar Loans [Member] | Regency Credit Facility [Member] | ||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.625% | |||||||||||||
PVR Acquisition [Member] | ||||||||||||||
Noncash or Part Noncash Acquisition, Debt Assumed | $ 1,200 | |||||||||||||
PVR Acquisition [Member] | 8.25% Senior Notes due April 15, 2018 [Member] | ||||||||||||||
Noncash or Part Noncash Acquisition, Debt Assumed | 300 | |||||||||||||
PVR Acquisition [Member] | 6.5% Senior Notes due May 15, 2021 [Member] | ||||||||||||||
Noncash or Part Noncash Acquisition, Debt Assumed | 400 | |||||||||||||
PVR Acquisition [Member] | 8.375% Senior Notes due June 1, 2020 [Member] | ||||||||||||||
Noncash or Part Noncash Acquisition, Debt Assumed | 473 | |||||||||||||
PVR Acquisition [Member] | Regency | 8.375% Senior Notes due June 1, 2020 [Member] | ||||||||||||||
Noncash or Part Noncash Acquisition, Debt Assumed | $ 473 |
Debt Obligations (Debt Instrume
Debt Obligations (Debt Instruments) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Long-term Debt | $ 25,981 | $ 20,398 |
Other | 223 | 228 |
Less: current maturities | (1,008) | (637) |
LONG-TERM DEBT, less current maturities | $ 24,973 | 19,761 |
Debt instrument interest rate | 4.50% | |
ETP [Member] | ||
Unamortized premiums, discounts and fair value adjustments, net | $ (1) | (34) |
Long-term Debt | 11,459 | 11,213 |
Transwestern [Member] | ||
Unamortized premiums, discounts and fair value adjustments, net | (1) | (1) |
Long-term Debt | 781 | 869 |
Panhandle [Member] | ||
Unamortized premiums, discounts and fair value adjustments, net | 99 | 155 |
Long-term Debt | 1,184 | 1,240 |
Regency | ||
Unamortized premiums, discounts and fair value adjustments, net | 48 | 0 |
Long-term Debt | 6,641 | 3,310 |
Sunoco [Member] | ||
Unamortized premiums, discounts and fair value adjustments, net | 35 | 70 |
Long-term Debt | 750 | 1,035 |
Sunoco Logistics [Member] | ||
Unamortized premiums, discounts and fair value adjustments, net | 100 | 118 |
Long-term Debt | 4,260 | 2,503 |
Sunoco LP [Member] | ||
Long-term Debt | 683 | 0 |
8.5% Senior Notes due April 15, 2014 | ETP [Member] | ||
Senior Notes | $ 0 | 292 |
Debt instrument interest rate | 8.50% | |
Debt instrument maturity date | Apr. 15, 2014 | |
5.95% Senior Notes due February 1, 2015 | ETP [Member] | ||
Senior Notes | $ 750 | 750 |
Debt instrument interest rate | 5.95% | |
Debt instrument maturity date | Feb. 1, 2015 | |
6.125% Senior Notes due February 15, 2017 | ETP [Member] | ||
Senior Notes | $ 400 | 400 |
Debt instrument interest rate | 6.125% | |
Debt instrument maturity date | Feb. 15, 2017 | |
6.7% Senior Notes due July 1, 2018 | ETP [Member] | ||
Senior Notes | $ 600 | 600 |
Debt instrument interest rate | 6.70% | |
Debt instrument maturity date | Jul. 1, 2018 | |
9.7% Senior Notes due March 15, 2019 | ETP [Member] | ||
Senior Notes | $ 400 | 400 |
Debt instrument interest rate | 9.70% | |
Debt instrument maturity date | Mar. 15, 2019 | |
9.0% Senior Notes due April 15, 2019 | ETP [Member] | ||
Senior Notes | $ 450 | 450 |
Debt instrument interest rate | 9.00% | |
Debt instrument maturity date | Apr. 15, 2019 | |
4.15% Senior Notes due October 1, 2020 | ETP [Member] | ||
Senior Notes | $ 700 | 700 |
Debt instrument interest rate | 4.15% | |
Debt instrument maturity date | Oct. 1, 2020 | |
4.65% Senior Notes due June 1, 2021 | ETP [Member] | ||
Senior Notes | $ 800 | 800 |
Debt instrument interest rate | 4.65% | |
Debt instrument maturity date | Jun. 1, 2021 | |
5.20% Senior Notes due February 1, 2022 | ETP [Member] | ||
Senior Notes | $ 1,000 | 1,000 |
Debt instrument interest rate | 5.20% | |
Debt instrument maturity date | Feb. 1, 2022 | |
3.60% Senior Notes due February 1, 2023 | ETP [Member] | ||
Senior Notes | $ 800 | 800 |
Debt instrument interest rate | 3.60% | |
Debt instrument maturity date | Feb. 1, 2023 | |
4.9% Senior Notes due February 1, 2024 | ETP [Member] | ||
Senior Notes | $ 350 | 350 |
Debt instrument interest rate | 4.90% | |
Debt instrument maturity date | Feb. 1, 2024 | |
7.60% Senior Notes due February 1, 2024 | ETP [Member] | ||
Senior Notes | $ 277 | 277 |
Debt instrument interest rate | 7.60% | |
Debt instrument maturity date | Feb. 1, 2024 | |
7.60% Senior Notes due February 1, 2024 | Panhandle [Member] | ||
Senior Notes | $ 82 | 82 |
8.25% Senior Notes due November 14, 2029 | ETP [Member] | ||
Senior Notes | $ 267 | 267 |
Debt instrument interest rate | 8.25% | |
Debt instrument maturity date | Nov. 15, 2029 | |
8.25% Senior Notes due November 14, 2029 | Panhandle [Member] | ||
Senior Notes | $ 33 | 33 |
6.625% Senior Notes due October 15, 2036 | ETP [Member] | ||
Senior Notes | $ 400 | 400 |
Debt instrument interest rate | 6.625% | |
Debt instrument maturity date | Oct. 15, 2036 | |
7.5% Senior Notes due July 1, 2038 | ETP [Member] | ||
Senior Notes | $ 550 | 550 |
Debt instrument interest rate | 7.50% | |
Debt instrument maturity date | Jul. 1, 2038 | |
6.05% Senior Notes due June 1, 2041 | ETP [Member] | ||
Senior Notes | $ 700 | 700 |
Debt instrument interest rate | 6.05% | |
Debt instrument maturity date | Jun. 1, 2041 | |
6.50% Senior Notes due February 1, 2042 | ETP [Member] | ||
Senior Notes | $ 1,000 | 1,000 |
Debt instrument interest rate | 6.50% | |
Debt instrument maturity date | Feb. 1, 2042 | |
5.15% Senior Notes due February 1, 2043 | ETP [Member] | ||
Senior Notes | $ 450 | 450 |
Debt instrument interest rate | 5.15% | |
Debt instrument maturity date | Feb. 1, 2043 | |
5.95% Senior Notes due October 1, 2043 | ETP [Member] | ||
Senior Notes | $ 450 | 450 |
Debt instrument interest rate | 5.95% | |
Debt instrument maturity date | Oct. 1, 2043 | |
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member] | ||
Junior Subordinated Notes | $ 546 | 546 |
Debt instrument maturity date | Nov. 1, 2066 | |
Debt Instrument, Interest Rate, Effective Percentage | 3.2571% | |
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member] | ||
Junior Subordinated Notes | $ 54 | 54 |
Debt instrument maturity date | Nov. 1, 2066 | |
6.875% Senior Notes, due December 1, 2018 [Member] | Regency | ||
Senior Notes | $ 0 | 600 |
Debt instrument interest rate | 6.88% | |
Debt instrument maturity date | Dec. 1, 2018 | |
5.75% Senior Notes due September 1, 2020 [Member] | Regency | ||
Senior Notes | $ 400 | 400 |
Debt instrument interest rate | 5.75% | |
Debt instrument maturity date | Sep. 1, 2020 | |
6.5% Senior Notes, due July 15, 2021 [Member] | Regency | ||
Senior Notes | $ 500 | 500 |
Debt instrument interest rate | 6.50% | |
Debt instrument maturity date | Jul. 15, 2021 | |
5.875% Senior Notes due March 1, 2022 [Member] | Regency | ||
Senior Notes | $ 900 | 0 |
Debt instrument interest rate | 5.875% | |
Debt instrument maturity date | Mar. 1, 2022 | |
5.5% Senior Notes, due April 15, 2023 [Member] | Regency | ||
Senior Notes | $ 700 | 700 |
Debt instrument interest rate | 5.50% | |
Debt instrument maturity date | Apr. 15, 2023 | |
4.5% Senior Notes due November 1, 2023 [Member] | Regency | ||
Senior Notes | $ 600 | 600 |
Debt instrument interest rate | 4.50% | |
Debt instrument maturity date | Nov. 1, 2023 | |
8.375% Senior Notes due June 1, 2020 [Member] | Regency | ||
Senior Notes | $ 390 | 0 |
Debt instrument interest rate | 8.375% | |
Debt instrument maturity date | Jun. 1, 2020 | |
6.5% Senior Notes due May 15, 2021 [Member] | Regency | ||
Senior Notes | $ 400 | 0 |
Debt instrument interest rate | 6.50% | |
Debt instrument maturity date | May 15, 2021 | |
8.375% Senior Notes due June 1, 2019 [Member] | Regency | ||
Senior Notes | $ 499 | 0 |
Debt instrument interest rate | 8.375% | |
Debt instrument maturity date | Jun. 1, 2019 | |
5.0% Senior Notes due October 1, 2022 [Member] | Regency | ||
Senior Notes | $ 700 | 0 |
Debt instrument interest rate | 5.00% | |
Debt instrument maturity date | Oct. 1, 2022 | |
Revolving Credit Facility [Member] | Regency | ||
Revolving credit facilities | $ 1,504 | 510 |
ETP $2.5 billion Revolving Credit Facility due October 27, 2019 | ETP [Member] | ||
Revolving credit facilities | $ 570 | 65 |
Debt instrument maturity date | Oct. 27, 2019 | |
5.39% Senior Notes due November 17, 2014 | Transwestern [Member] | ||
Senior Notes | $ 0 | 88 |
Debt instrument interest rate | 5.39% | |
Debt instrument maturity date | Nov. 17, 2014 | |
5.54% Senior Notes due November 17, 2016 | Transwestern [Member] | ||
Senior Notes | $ 125 | 125 |
Debt instrument interest rate | 5.54% | |
Debt instrument maturity date | Nov. 17, 2016 | |
5.64% Senior Notes due May 24, 2017 | Transwestern [Member] | ||
Senior Notes | $ 82 | 82 |
Debt instrument interest rate | 5.64% | |
Debt instrument maturity date | May 24, 2017 | |
5.36% Senior Notes due December 9, 2020 | Transwestern [Member] | ||
Senior Notes | $ 175 | 175 |
Debt instrument interest rate | 5.36% | |
Debt instrument maturity date | Dec. 9, 2020 | |
5.89% Senior Notes due May 24, 2022 | Transwestern [Member] | ||
Senior Notes | $ 150 | 150 |
Debt instrument interest rate | 5.89% | |
Debt instrument maturity date | May 24, 2022 | |
5.66% Senior Notes due December 9, 2024 | Transwestern [Member] | ||
Senior Notes | $ 175 | 175 |
Debt instrument interest rate | 5.66% | |
Debt instrument maturity date | Dec. 9, 2024 | |
6.16% Senior Notes due May 24, 2037 | Transwestern [Member] | ||
Senior Notes | $ 75 | 75 |
Debt instrument interest rate | 6.16% | |
Debt instrument maturity date | May 24, 2037 | |
6.20% Senior Notes due November 1, 2017 | Panhandle [Member] | ||
Senior Notes | $ 300 | 300 |
Debt instrument interest rate | 6.20% | |
Debt instrument maturity date | Nov. 1, 2017 | |
7.00% Senior Notes due June 15, 2018 | Panhandle [Member] | ||
Senior Notes | $ 400 | 400 |
Debt instrument interest rate | 7.00% | |
Debt instrument maturity date | Jun. 15, 2018 | |
8.125% Senior Notes due June 1, 2019 | Panhandle [Member] | ||
Senior Notes | $ 150 | 150 |
Debt instrument interest rate | 8.125% | |
Debt instrument maturity date | Jun. 1, 2019 | |
7.00% Senior Notes due July 15, 2029 | Panhandle [Member] | ||
Senior Notes | $ 66 | 66 |
Debt instrument interest rate | 7.00% | |
Debt instrument maturity date | Jul. 15, 2029 | |
4.875% Senior Notes due October 15, 2014 | Sunoco [Member] | ||
Senior Notes | $ 0 | 250 |
Debt instrument interest rate | 4.875% | |
Debt instrument maturity date | Oct. 15, 2014 | |
9.625% Senior Notes due April 15, 2015 | Sunoco [Member] | ||
Senior Notes | $ 250 | 250 |
Debt instrument interest rate | 9.625% | |
Debt instrument maturity date | Apr. 15, 2015 | |
5.75% Senior Notes due January 15, 2017 | Sunoco [Member] | ||
Senior Notes | $ 400 | 400 |
Debt instrument interest rate | 5.75% | |
Debt instrument maturity date | Jan. 15, 2017 | |
9.00% Debentures due November 1, 2024 | Sunoco [Member] | ||
Subordinated Debt | $ 65 | 65 |
Debt instrument interest rate | 9.00% | |
Debt instrument maturity date | Nov. 1, 2024 | |
8.75% Senior Notes due February 15, 2014(2) | Sunoco Logistics [Member] | ||
Senior Notes | $ 0 | 175 |
Debt instrument interest rate | 8.75% | |
Debt instrument maturity date | Feb. 15, 2014 | |
6.125% Senior Notes due May 15, 2016 | Sunoco Logistics [Member] | ||
Senior Notes | $ 175 | 175 |
Debt instrument interest rate | 6.125% | |
Debt instrument maturity date | May 15, 2016 | |
5.50% Senior Notes due February 15, 2020 | Sunoco Logistics [Member] | ||
Senior Notes | $ 250 | 250 |
Debt instrument interest rate | 5.50% | |
Debt instrument maturity date | Feb. 15, 2020 | |
4.65% Senior Notes due February 15, 2022 | Sunoco Logistics [Member] | ||
Senior Notes | $ 300 | 300 |
Debt instrument interest rate | 4.65% | |
Debt instrument maturity date | Feb. 15, 2022 | |
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member] | ||
Senior Notes | $ 350 | 350 |
Debt instrument interest rate | 3.45% | |
Debt instrument maturity date | Jan. 15, 2023 | |
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member] | ||
Senior Notes | $ 500 | 0 |
Debt instrument interest rate | 4.25% | |
Debt instrument maturity date | Apr. 1, 2024 | |
6.85% Senior Notes due February 15, 2040 | Sunoco Logistics [Member] | ||
Senior Notes | $ 250 | 250 |
Debt instrument interest rate | 6.85% | |
Debt instrument maturity date | Feb. 15, 2040 | |
6.10% Senior Notes due February 15, 2042 | Sunoco Logistics [Member] | ||
Senior Notes | $ 300 | 300 |
Debt instrument interest rate | 6.10% | |
Debt instrument maturity date | Feb. 15, 2042 | |
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member] | ||
Senior Notes | $ 350 | 350 |
Debt instrument interest rate | 4.95% | |
Debt instrument maturity date | Jan. 15, 2043 | |
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member] | ||
Senior Notes | $ 700 | 0 |
Debt instrument interest rate | 5.30% | |
Debt instrument maturity date | Apr. 1, 2044 | |
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member] | ||
Senior Notes | $ 800 | 0 |
Debt instrument interest rate | 5.35% | |
Debt instrument maturity date | May 15, 2045 | |
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015(3) | Sunoco Logistics [Member] | ||
Revolving credit facilities | $ 35 | 35 |
Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018 | Sunoco Logistics [Member] | ||
Revolving credit facilities | 150 | 200 |
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019 | Sunoco LP [Member] | ||
Revolving credit facilities | $ 683 | $ 0 |
Debt Obligations Debt Instrumen
Debt Obligations Debt Instruments (Parenthetical) (Details) - Dec. 31, 2014 | Total |
Senior note interest rate | 4.50% |
8.75% Senior Notes due February 15, 2014(2) | Sunoco Logistics [Member] | |
Senior note interest rate | 8.75% |
Debt instrument maturity date | Feb. 15, 2014 |
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member] | |
Senior note interest rate | 4.25% |
Debt instrument maturity date | Apr. 1, 2024 |
6.85% Senior Notes due February 15, 2040 | Sunoco Logistics [Member] | |
Senior note interest rate | 6.85% |
Debt instrument maturity date | Feb. 15, 2040 |
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member] | |
Senior note interest rate | 5.30% |
Debt instrument maturity date | Apr. 1, 2044 |
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member] | |
Senior note interest rate | 5.35% |
Debt instrument maturity date | May 15, 2045 |
8.5% Senior Notes due April 15, 2014 | ETP [Member] | |
Senior note interest rate | 8.50% |
Debt instrument maturity date | Apr. 15, 2014 |
5.95% Senior Notes due February 1, 2015 | ETP [Member] | |
Senior note interest rate | 5.95% |
Debt instrument maturity date | Feb. 1, 2015 |
6.125% Senior Notes due February 15, 2017 | ETP [Member] | |
Senior note interest rate | 6.125% |
Debt instrument maturity date | Feb. 15, 2017 |
6.7% Senior Notes due July 1, 2018 | ETP [Member] | |
Senior note interest rate | 6.70% |
Debt instrument maturity date | Jul. 1, 2018 |
9.7% Senior Notes due March 15, 2019 | ETP [Member] | |
Senior note interest rate | 9.70% |
Debt instrument maturity date | Mar. 15, 2019 |
9.0% Senior Notes due April 15, 2019 | ETP [Member] | |
Senior note interest rate | 9.00% |
Debt instrument maturity date | Apr. 15, 2019 |
4.15% Senior Notes due October 1, 2020 | ETP [Member] | |
Senior note interest rate | 4.15% |
Debt instrument maturity date | Oct. 1, 2020 |
4.65% Senior Notes due June 1, 2021 | ETP [Member] | |
Senior note interest rate | 4.65% |
Debt instrument maturity date | Jun. 1, 2021 |
5.20% Senior Notes due February 1, 2022 | ETP [Member] | |
Senior note interest rate | 5.20% |
Debt instrument maturity date | Feb. 1, 2022 |
3.60% Senior Notes due February 1, 2023 | ETP [Member] | |
Senior note interest rate | 3.60% |
Debt instrument maturity date | Feb. 1, 2023 |
4.9% Senior Notes due February 1, 2024 | ETP [Member] | |
Senior note interest rate | 4.90% |
Debt instrument maturity date | Feb. 1, 2024 |
7.60% Senior Notes due February 1, 2024 | ETP [Member] | |
Senior note interest rate | 7.60% |
Debt instrument maturity date | Feb. 1, 2024 |
7.60% Senior Notes due February 1, 2024 | Southern Union [Member] | |
Senior note interest rate | 7.60% |
Debt instrument maturity date | Feb. 1, 2024 |
8.25% Senior Notes due November 14, 2029 | ETP [Member] | |
Senior note interest rate | 8.25% |
Debt instrument maturity date | Nov. 15, 2029 |
8.25% Senior Notes due November 14, 2029 | Southern Union [Member] | |
Senior note interest rate | 8.25% |
Debt instrument maturity date | Nov. 14, 2029 |
6.625% Senior Notes due October 15, 2036 | ETP [Member] | |
Senior note interest rate | 6.625% |
Debt instrument maturity date | Oct. 15, 2036 |
7.5% Senior Notes due July 1, 2038 | ETP [Member] | |
Senior note interest rate | 7.50% |
Debt instrument maturity date | Jul. 1, 2038 |
6.05% Senior Notes due June 1, 2041 | ETP [Member] | |
Senior note interest rate | 6.05% |
Debt instrument maturity date | Jun. 1, 2041 |
6.50% Senior Notes due February 1, 2042 | ETP [Member] | |
Senior note interest rate | 6.50% |
Debt instrument maturity date | Feb. 1, 2042 |
5.15% Senior Notes due February 1, 2043 | ETP [Member] | |
Senior note interest rate | 5.15% |
Debt instrument maturity date | Feb. 1, 2043 |
5.95% Senior Notes due October 1, 2043 | ETP [Member] | |
Senior note interest rate | 5.95% |
Debt instrument maturity date | Oct. 1, 2043 |
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member] | |
Debt instrument maturity date | Nov. 1, 2066 |
Debt Instrument, Interest Rate, Effective Percentage | 3.2571% |
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member] | |
Debt instrument maturity date | Nov. 1, 2066 |
6.875% Senior Notes, due December 1, 2018 [Member] | Regency | |
Senior note interest rate | 6.88% |
Debt instrument maturity date | Dec. 1, 2018 |
5.75% Senior Notes due September 1, 2020 [Member] | Regency | |
Senior note interest rate | 5.75% |
Debt instrument maturity date | Sep. 1, 2020 |
6.5% Senior Notes, due July 15, 2021 [Member] | Regency | |
Senior note interest rate | 6.50% |
Debt instrument maturity date | Jul. 15, 2021 |
5.875% Senior Notes due March 1, 2022 [Member] | Regency | |
Senior note interest rate | 5.875% |
Debt instrument maturity date | Mar. 1, 2022 |
5.5% Senior Notes, due April 15, 2023 [Member] | Regency | |
Senior note interest rate | 5.50% |
Debt instrument maturity date | Apr. 15, 2023 |
4.5% Senior Notes due November 1, 2023 [Member] | Regency | |
Senior note interest rate | 4.50% |
Debt instrument maturity date | Nov. 1, 2023 |
8.375% Senior Notes due June 1, 2020 [Member] | Regency | |
Senior note interest rate | 8.375% |
Debt instrument maturity date | Jun. 1, 2020 |
6.5% Senior Notes due May 15, 2021 [Member] | Regency | |
Senior note interest rate | 6.50% |
Debt instrument maturity date | May 15, 2021 |
8.375% Senior Notes due June 1, 2019 [Member] | Regency | |
Senior note interest rate | 8.375% |
Debt instrument maturity date | Jun. 1, 2019 |
5.0% Senior Notes due October 1, 2022 [Member] | Regency | |
Senior note interest rate | 5.00% |
Debt instrument maturity date | Oct. 1, 2022 |
ETP $2.5 billion Revolving Credit Facility due October 27, 2019 | ETP [Member] | |
Debt instrument maturity date | Oct. 27, 2019 |
5.39% Senior Notes due November 17, 2014 | Transwestern [Member] | |
Senior note interest rate | 5.39% |
Debt instrument maturity date | Nov. 17, 2014 |
5.54% Senior Notes due November 17, 2016 | Transwestern [Member] | |
Senior note interest rate | 5.54% |
Debt instrument maturity date | Nov. 17, 2016 |
5.64% Senior Notes due May 24, 2017 | Transwestern [Member] | |
Senior note interest rate | 5.64% |
Debt instrument maturity date | May 24, 2017 |
5.36% Senior Notes due December 9, 2020 | Transwestern [Member] | |
Senior note interest rate | 5.36% |
Debt instrument maturity date | Dec. 9, 2020 |
5.89% Senior Notes due May 24, 2022 | Transwestern [Member] | |
Senior note interest rate | 5.89% |
Debt instrument maturity date | May 24, 2022 |
5.66% Senior Notes due December 9, 2024 | Transwestern [Member] | |
Senior note interest rate | 5.66% |
Debt instrument maturity date | Dec. 9, 2024 |
6.16% Senior Notes due May 24, 2037 | Transwestern [Member] | |
Senior note interest rate | 6.16% |
Debt instrument maturity date | May 24, 2037 |
6.20% Senior Notes due November 1, 2017 | Panhandle [Member] | |
Senior note interest rate | 6.20% |
Debt instrument maturity date | Nov. 1, 2017 |
7.00% Senior Notes due June 15, 2018 | Panhandle [Member] | |
Senior note interest rate | 7.00% |
Debt instrument maturity date | Jun. 15, 2018 |
8.125% Senior Notes due June 1, 2019 | Panhandle [Member] | |
Senior note interest rate | 8.125% |
Debt instrument maturity date | Jun. 1, 2019 |
7.00% Senior Notes due July 15, 2029 | Panhandle [Member] | |
Senior note interest rate | 7.00% |
Debt instrument maturity date | Jul. 15, 2029 |
4.875% Senior Notes due October 15, 2014 | Sunoco [Member] | |
Senior note interest rate | 4.875% |
Debt instrument maturity date | Oct. 15, 2014 |
9.625% Senior Notes due April 15, 2015 | Sunoco [Member] | |
Senior note interest rate | 9.625% |
Debt instrument maturity date | Apr. 15, 2015 |
6.125% Senior Notes due May 15, 2016 | Sunoco Logistics [Member] | |
Senior note interest rate | 6.125% |
Debt instrument maturity date | May 15, 2016 |
5.50% Senior Notes due February 15, 2020 | Sunoco Logistics [Member] | |
Senior note interest rate | 5.50% |
Debt instrument maturity date | Feb. 15, 2020 |
4.65% Senior Notes due February 15, 2022 | Sunoco Logistics [Member] | |
Senior note interest rate | 4.65% |
Debt instrument maturity date | Feb. 15, 2022 |
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member] | |
Senior note interest rate | 3.45% |
Debt instrument maturity date | Jan. 15, 2023 |
6.10% Senior Notes due February 15, 2042 | Sunoco Logistics [Member] | |
Senior note interest rate | 6.10% |
Debt instrument maturity date | Feb. 15, 2042 |
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member] | |
Senior note interest rate | 4.95% |
Debt instrument maturity date | Jan. 15, 2043 |
5.75% Senior Notes due January 15, 2017 | Sunoco [Member] | |
Senior note interest rate | 5.75% |
Debt instrument maturity date | Jan. 15, 2017 |
9.00% Debentures due November 1, 2024 | Sunoco [Member] | |
Senior note interest rate | 9.00% |
Debt instrument maturity date | Nov. 1, 2024 |
Line Of Credit Maturity October 27, 2016 [Member] | ETP $2.5 billion Revolving Credit Facility due October 27, 2019 | ETP [Member] | |
Weighted average interest rate on the total amount outstanding | 1.66205% |
Debt Obligations (Future maturi
Debt Obligations (Future maturities of long-term debt) (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
2,015 | $ 1,050 | |
2,016 | 314 | |
2,017 | 1,228 | |
2,018 | 1,155 | |
2,019 | 4,262 | |
Thereafter | 17,692 | |
Long-term Debt | 25,981 | $ 20,398 |
Excluding unamortized premiums and fair value adjustments [Member] | ||
Long-term Debt | $ 25,701 |
Series A Preferred Units (Detai
Series A Preferred Units (Details) shares in Millions | 6 Months Ended | |
Jun. 30, 2015shares | Apr. 30, 2015USD ($)$ / commonunitshares | |
Preferred Units Redemption Amount | $ 35,000,000 | |
Preferred Units Quarterly Cash Distribution Per Unit | $ / commonunit | 0.445 | |
Preferrred Units Issued Stated Price | $ 18.30 | |
Conversion Price of Preferred Units | $ 44.37 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares | 0.9 | |
Regency Merger [Member] | ||
Preferred Units, Issued | shares | 1.9 |
Equity (Narrative) (Details)
Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions | Jan. 26, 2015 | Mar. 31, 2012 | Mar. 31, 2012 | Apr. 30, 2015 | Mar. 31, 2015 | Apr. 30, 2013 | Jul. 31, 2012 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 05, 2012 | Dec. 31, 2011 |
CLASS H UNITHOLDER’S INTEREST IN NET INCOME | $ 217 | $ 48 | $ 0 | ||||||||||||||
Partners' Capital Account, Units | 355,500,000 | 355,500,000 | 333,800,000 | 301,500,000 | 225,500,000 | ||||||||||||
Class F Unit Distribution Rate | 35.00% | 35.00% | |||||||||||||||
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest | 99.30% | ||||||||||||||||
Common Units issued in connection with the Distribution Reinvestment Plan | 2,800,000 | 2,300,000 | 1,000,000 | ||||||||||||||
Class E Units entitled to aggregate cash distributions | 11.10% | 11.10% | |||||||||||||||
Class E unit maximum distribution | $ 1.41 | $ 1.41 | |||||||||||||||
Maximum Class F Distribution per Unit | $ 3.75 | $ 3.75 | |||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 2,200,000 | ||||||||||||||||
Common Units issued in connection with the equity distribution program | 21,400,000 | 16,900,000 | 1,600,000 | ||||||||||||||
Net proceeds from issuance of Common Units | $ 1,382 | $ 1,611 | $ 791 | ||||||||||||||
Partners' Capital Account, Sale of Units | $ 1,382 | 1,611 | 791 | ||||||||||||||
ETP [Member] | |||||||||||||||||
Equity Distribution Agreements, Value of Units Available to be Issued | $ 832 | ||||||||||||||||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 2,800,000 | 6,100,000 | |||||||||||||||
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan | 7,300,000 | 4,500,000 | 7,300,000 | ||||||||||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 155 | $ 155 | $ 109 | $ 43 | |||||||||||||
Net proceeds from issuance of Common Units | $ 657 | $ 671 | |||||||||||||||
Sunoco Logistics [Member] | |||||||||||||||||
Gain from subsidiary issuances of common units | 113 | ||||||||||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | $ 1,250 | ||||||||||||||||
Proceeds from Issuance of Common Stock | $ 82 | $ 547 | |||||||||||||||
Common Units issued in connection with the equity distribution program | 10,300,000 | ||||||||||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $ 477 | ||||||||||||||||
Fees and Commissions | 5 | ||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 7,700,000 | 13,500,000 | |||||||||||||||
Partners' Capital Account, Sale of Units | $ 362 | ||||||||||||||||
Stock Issued During Period, Shares, New Issues | 2,000,000 | ||||||||||||||||
Sunoco LP [Member] | |||||||||||||||||
Gain from subsidiary issuances of common units | $ 62 | ||||||||||||||||
Proceeds from Issuance of Common Stock | $ 213 | ||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 9,100,000 | ||||||||||||||||
Partners' Capital Account, Sale of Units | $ 405 | ||||||||||||||||
Stock Issued During Period, Shares, New Issues | 5,500,000 | ||||||||||||||||
Regency | |||||||||||||||||
Net proceeds from issuance of Common Units | $ 297 | ||||||||||||||||
Class E Units | |||||||||||||||||
Limited Partners' Capital Account, Units Outstanding | 8,853,832 | 8,853,832 | 8,853,832 | ||||||||||||||
Eagle Rock Midstream Acquisition [Member] | Regency | |||||||||||||||||
Stock Issued During Period, Shares, Acquisitions | 8,200,000 | ||||||||||||||||
Proceeds from Issuance of Common Stock | $ 400 | ||||||||||||||||
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% | ||||||||||||||||
Class I Distributions | $ 30 | $ 55 | |||||||||||||||
Class F Units [Member] | Sunoco [Member] | |||||||||||||||||
Partners' Capital Account, Units | 40,000,000 | 40,000,000 | |||||||||||||||
Class G Units | ETP Holdco Transaction | |||||||||||||||||
Partners' Capital Account, Units | 90,700,000 | ||||||||||||||||
Class H Units | |||||||||||||||||
Partners' Capital Account, Units | 50,200,000 | 50,200,000 | |||||||||||||||
Allocation of Profits, Losses and Other by Sunoco, Percent | 50.05% | 50.05% | |||||||||||||||
2012 Agreement [Member] | Regency | |||||||||||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | $ 200 | ||||||||||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | 34 | $ 149 | |||||||||||||||
2014 Agreement [Member] | Regency | |||||||||||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | 400 | ||||||||||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | 395 | ||||||||||||||||
2015 Agreement [Member] | Regency | |||||||||||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | $ 1,000 | ||||||||||||||||
November 2014 [Member] | |||||||||||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | 1,500 | ||||||||||||||||
2014 Plans [Member] | |||||||||||||||||
Equity Distribution Agreements, Value of Units Available to be Issued | $ 1,410 | $ 1,410 | |||||||||||||||
Common Units issued in connection with the equity distribution program | 18,800,000 | ||||||||||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $ 1,080 | ||||||||||||||||
Fees and Commissions | 11 | ||||||||||||||||
January 2013 [Member] | |||||||||||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | 200 | ||||||||||||||||
May 2013 [Member] | |||||||||||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | $ 800 | ||||||||||||||||
2013 Plans [Member] | |||||||||||||||||
Common Units issued in connection with the equity distribution program | 2,700,000 | ||||||||||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $ 144 | ||||||||||||||||
Fees and Commissions | 2 | ||||||||||||||||
May 2014 [Member] | |||||||||||||||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | $ 1,000 | ||||||||||||||||
Equity Distribution Agreement [Member] | ETP [Member] | |||||||||||||||||
Proceeds from Issuance of Common Stock | $ 569 | ||||||||||||||||
Fees and Commissions | 6 | ||||||||||||||||
Equity Distribution Agreement [Member] | Sunoco Logistics [Member] | |||||||||||||||||
Fees and Commissions | 4 | ||||||||||||||||
Net proceeds from issuance of Common Units | $ 385 | ||||||||||||||||
Issued to wholly-owned subsidiary of ETE [Member] | Regency | |||||||||||||||||
Stock Issued During Period, Shares, New Issues | 14,400,000 | ||||||||||||||||
Stock Issued During Period, Value, New Issues | $ 400 | ||||||||||||||||
Issued to wholly-owned subsidiary of ETE [Member] | Eagle Rock Midstream Acquisition [Member] | Regency | |||||||||||||||||
Stock Issued During Period, Shares, New Issues | 16,500,000 | ||||||||||||||||
Stock Issued During Period, Value, New Issues | $ 400 | ||||||||||||||||
Class I Units [Member] | Bakken Pipeline Transaction [Member] | |||||||||||||||||
Business Acquisition Units Acquired | 100 | ||||||||||||||||
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 E Units | ETP [Member] | |||||||||||||||||
Limited Partners' Capital Account, Units Outstanding | 8,900,000 | 8,900,000 | |||||||||||||||
Bakken Exchange [Member] | Class I Units [Member] | |||||||||||||||||
Partners' Capital Account, Units | 100 |
Equity (Change in Common Units)
Equity (Change in Common Units) (Details) - shares shares in Millions | Mar. 31, 2012 | Aug. 31, 2014 | Feb. 28, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Number of Common Units, beginning of period | 333.8 | 301.5 | 225.5 | |||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 2.2 | |||||
Common Units issued in connection with public offerings | 0 | 13.8 | 15.5 | |||
Partners' Capital Account, Units, Acquisitions | 0 | 49.5 | 57.4 | |||
Common Units Redeemed for Class H Units | 0 | (50.2) | 0 | |||
Common Units issued in connection with the Distribution Reinvestment Plan | 2.8 | 2.3 | 1 | |||
Common Units issued in connection with the equity distribution program | 21.4 | 16.9 | 1.6 | |||
Stock Repurchased During Period, Shares | 0 | (0.4) | 0 | |||
Issuance of Common Units under equity incentive plans | 0.4 | 0.4 | 0.5 | |||
Number of Common Units, end of period | 355.5 | 333.8 | 301.5 | |||
Susser Merger | ||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 15.8 | 0 | 0 | 0 | ||
Lake Charles LNG Transaction [Member] | ||||||
Partners' Capital Account, Units, Redeemed | 18.7 | (18.7) | 0 | 0 |
Equity (Public Offerings of Com
Equity (Public Offerings of Common Units) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||
Apr. 30, 2013 | Jul. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Common Units issued in connection with public offerings | 0 | 13.8 | 15.5 | ||
Net Proceeds | $ 1,382 | $ 1,611 | $ 791 | ||
ETP [Member] | |||||
Common Units issued in connection with public offerings | 13.8 | 15.5 | |||
Price per Unit | $ 48.05 | $ 44.57 | |||
Net Proceeds | $ 657 | $ 671 |
Equity (Quarterly Distributions
Equity (Quarterly Distributions of Available Cash) (Details) - $ / shares | 3 Months Ended | ||||||||||||||
Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2011 | |
Equity [Abstract] | |||||||||||||||
Distribution Made to Limited Partner, Date of Record | Aug. 6, 2015 | May 8, 2015 | Feb. 6, 2015 | Nov. 3, 2014 | Aug. 4, 2014 | May 5, 2014 | Feb. 7, 2014 | Nov. 4, 2013 | Aug. 5, 2013 | May 6, 2013 | Feb. 7, 2013 | Nov. 6, 2012 | Aug. 6, 2012 | May 4, 2012 | Feb. 7, 2012 |
Distribution Made to Limited Partner, Distribution Date | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 15, 2014 | Feb. 14, 2014 | Nov. 14, 2013 | Aug. 14, 2013 | May 15, 2013 | Feb. 14, 2013 | Nov. 14, 2012 | Aug. 14, 2012 | May 15, 2012 | Feb. 14, 2012 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 1.0350 | $ 1.0150 | $ 0.9950 | $ 0.9750 | $ 0.9550 | $ 0.9350 | $ 0.9200 | $ 0.9050 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 |
Equity (Incentive Distribution
Equity (Incentive Distribution Relinquishments) (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Equity [Abstract] | |||||
Relinquishment of Incentive Distributions | $ 56 | $ 95 | $ 105 | $ 128 | $ 137 |
Equity (SXL Quarterly Distribut
Equity (SXL Quarterly Distributions) (Details) - $ / shares | 3 Months Ended | ||||||||||||||
Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2011 | |
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Distribution Made to Limited Partner, Date of Record | Aug. 6, 2015 | May 8, 2015 | Feb. 6, 2015 | Nov. 3, 2014 | Aug. 4, 2014 | May 5, 2014 | Feb. 7, 2014 | Nov. 4, 2013 | Aug. 5, 2013 | May 6, 2013 | Feb. 7, 2013 | Nov. 6, 2012 | Aug. 6, 2012 | May 4, 2012 | Feb. 7, 2012 |
Distribution Made to Limited Partner, Distribution Date | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 15, 2014 | Feb. 14, 2014 | Nov. 14, 2013 | Aug. 14, 2013 | May 15, 2013 | Feb. 14, 2013 | Nov. 14, 2012 | Aug. 14, 2012 | May 15, 2012 | Feb. 14, 2012 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 1.0350 | $ 1.0150 | $ 0.9950 | $ 0.9750 | $ 0.9550 | $ 0.9350 | $ 0.9200 | $ 0.9050 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 |
Sunoco Logistics [Member] | |||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||
Distribution Made to Limited Partner, Date of Record | Aug. 10, 2015 | May 11, 2015 | Feb. 9, 2015 | Nov. 7, 2014 | Aug. 8, 2014 | May 9, 2014 | Feb. 10, 2014 | Nov. 8, 2013 | Aug. 8, 2013 | May 9, 2013 | Feb. 8, 2013 | ||||
Distribution Made to Limited Partner, Distribution Date | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 15, 2014 | Feb. 14, 2014 | Nov. 14, 2013 | Aug. 14, 2013 | May 15, 2013 | Feb. 14, 2013 | ||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.4380 | $ 0.4190 | $ 0.4000 | $ 0.3825 | $ 0.3650 | $ 0.3475 | $ 0.3312 | $ 0.3150 | $ 0.3000 | $ 0.2863 | $ 0.2725 |
Equity Sunoco LP Quarterly DIst
Equity Sunoco LP Quarterly DIstributions (Details) - $ / shares | 3 Months Ended | ||||||||||||||
Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2011 | |
Distribution Made to Limited Partner, Date of Record | Aug. 6, 2015 | May 8, 2015 | Feb. 6, 2015 | Nov. 3, 2014 | Aug. 4, 2014 | May 5, 2014 | Feb. 7, 2014 | Nov. 4, 2013 | Aug. 5, 2013 | May 6, 2013 | Feb. 7, 2013 | Nov. 6, 2012 | Aug. 6, 2012 | May 4, 2012 | Feb. 7, 2012 |
Distribution Made to Limited Partner, Distribution Date | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 15, 2014 | Feb. 14, 2014 | Nov. 14, 2013 | Aug. 14, 2013 | May 15, 2013 | Feb. 14, 2013 | Nov. 14, 2012 | Aug. 14, 2012 | May 15, 2012 | Feb. 14, 2012 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 1.0350 | $ 1.0150 | $ 0.9950 | $ 0.9750 | $ 0.9550 | $ 0.9350 | $ 0.9200 | $ 0.9050 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 | $ 0.8938 |
Sunoco LP [Member] | |||||||||||||||
Distribution Made to Limited Partner, Date of Record | Aug. 18, 2015 | May 19, 2015 | Feb. 17, 2015 | Nov. 18, 2014 | |||||||||||
Distribution Made to Limited Partner, Distribution Date | Aug. 28, 2015 | May 29, 2015 | Feb. 27, 2015 | Nov. 28, 2014 | |||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.6934 | $ 0.6450 | $ 0.6000 | $ 0.5457 |
Equity (Regency Equity Offering
Equity (Regency Equity Offerings) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | Mar. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Common Units issued in connection with public offerings | 0 | 13.8 | 15.5 | |
Net proceeds from issuance of Common Units | $ 1,382 | $ 1,611 | $ 791 | |
Regency | ||||
Common Units issued in connection with public offerings | 12.7 | |||
Price per Unit | $ 24.47 | |||
Net proceeds from issuance of Common Units | $ 297 |
Equity (Accumulated other compr
Equity (Accumulated other comprehensive income, net of tax) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Equity [Abstract] | ||
Available-for-sale securities | $ 3 | $ 2 |
Foreign currency translation adjustment | (3) | (1) |
Net loss on commodity related hedges | (1) | (4) |
Actuarial gain (loss) related to pensions and other postretirement benefits | (57) | 56 |
Equity investments, net | 2 | 8 |
Total AOCI, net of tax | $ (56) | $ 61 |
Equity (Tax amounts attributabl
Equity (Tax amounts attributable to Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Equity [Abstract] | ||
Other Comprehensive Income (Loss), Available-for-sale Securities, Tax | $ (1) | $ (1) |
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax | 2 | 1 |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax | (37) | (39) |
Other Comprehensive Income (Loss), Tax | $ (36) | $ (39) |
Unit-Based Compensation Plans86
Unit-Based Compensation Plans (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Weighted average grant-date fair value per unit award granted | $ 60.85 | $ 50.54 | $ 43.93 |
Total fair value of awards vested | $ 26 | $ 29 | $ 29 |
Unvested unit awards outstanding | 3,600,000 | 3,200,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 5,400,000 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 53.83 | $ 49.65 | |
Employee [Member] | |||
Share based compensation, vesting term | 5 years | ||
Director [Member] | |||
Share based compensation, vesting term | 5 years | ||
ETP Unit-Based Compensation Plans [Member] | |||
Awards remaining unvested compensation expense | $ 128 | ||
Awards remaining unvested weighted average period, in years | 2 years | ||
ETP Cash Restricted Units [Member] | |||
Unvested unit awards outstanding | 400,000 | ||
Awards remaining unvested compensation expense | $ 24 | ||
Awards remaining unvested weighted average period, in years | 1 year 9 months 15 days | ||
Sunoco Logistics Unit-Based Compensation Plans [Member] | |||
Unvested unit awards outstanding | 1,500,000 | ||
Awards remaining unvested compensation expense | $ 33 | ||
Awards remaining unvested weighted average period, in years | 2 years 11 months | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 700,000 | ||
Regency Common Unit Options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number | 107,650 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price | $ 22.68 | ||
Regency Phantom Units [Member] | |||
Unvested unit awards outstanding | 2,167,719 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 24.31 | ||
Regency Cash Restricted Units [Member] | |||
Unvested unit awards outstanding | 379,328 |
Unit-Based Compensation Plans87
Unit-Based Compensation Plans (Activity of the awards granted to employees and non-employee directors) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Unvested awards as of December 31, 2010 , Number of Units | 3.2 | ||
Awards granted, Number of Units | 1 | ||
Awards vested, Number of Units | (0.5) | ||
Unvested awards as of December 31, 2011, Number of Units | 3.6 | 3.2 | |
Unvested awards as of December 31, 2010, Weighted Average Grant-Date Fair Value Per Unit | $ 49.65 | ||
Weighted average grant-date fair value per unit award granted | 60.85 | $ 50.54 | $ 43.93 |
Awards vested, Weighted Average Grant-Date Fair Value Per Unit | 48.12 | ||
Awards forfeited, Weighted Average Grant-Date Fair Value Per Unit | 32.36 | ||
Unvested awards as of December 31, 2011, Weighted Average Grant-Date Fair Value Per Unit | $ 53.83 | $ 49.65 | |
ETP Unit-Based Compensation Plans [Member] | |||
Stock Granted, Value, Share-based Compensation, Forfeited | $ (0.1) |
Income Taxes Narrative (Details
Income Taxes Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2014 | Jul. 31, 2015 | Jun. 30, 2015 | Dec. 31, 2013 | |
Income Tax Contingency [Line Items] | ||||
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax | $ 425 | |||
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit | $ 4 | |||
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Other Information | 2 | |||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | $ 1 | |||
Operating Loss Carryforwards | 5 | |||
Net operating losses and alternative minimum tax credit | 116 | $ 217 | ||
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 439 | |||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 6 | |||
Amount of Deferred Gain Challenged by IRS | 545 | |||
Deferred Gain Associated with Like Kind Exchange | 690 | |||
Deferred Tax Assets, Valuation Allowance | 84 | $ 74 | ||
Pending Tax Refund | 372 | |||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts | 372 | |||
Expiring 2013 to 2032 [Member] | ||||
Income Tax Contingency [Line Items] | ||||
Operating Loss Carryforwards | 111 | |||
Tax Year 2006 [Member] | ||||
Income Tax Contingency [Line Items] | ||||
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | $ 6 | |||
Holdco [Member] | ||||
Income Tax Contingency [Line Items] | ||||
Net operating losses and alternative minimum tax credit | $ 1 | |||
Sunoco [Member] | ||||
Income Tax Contingency [Line Items] | ||||
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | $ 87 | |||
Sunoco [Member] | Net of federal tax [Member] | ||||
Income Tax Contingency [Line Items] | ||||
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | $ 57 |
Income Taxes Compoenents of Fed
Income Taxes Compoenents of Federal and State Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Current expense (benefit): | |||
Federal | $ 321 | $ 51 | $ (3) |
State | 86 | (2) | 4 |
Current expense (benefit) - Total | 407 | 49 | 1 |
Deferred expense (benefit): | |||
Federal | (50) | (6) | 45 |
State | 1 | 54 | 17 |
Deferred expense (benefit) - Total | (49) | 48 | 62 |
Income tax from continuing operations | $ 358 | $ 97 | $ 63 |
Income Taxes Statutory Income T
Income Taxes Statutory Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Schedule of Effective Income Tax Rate Reconciliation [Line Items] | |||
Income tax expense (benefit) at U.S. statutory rate of 35 percent | $ 217 | $ (166) | |
Nondeductible goodwill | 0 | 241 | |
Nondeductible goodwill included in the Lake Charles LNG Transaction | 105 | 0 | |
State income taxes (net of federal income tax effects) | 54 | 36 | |
Premium on debt retirement | (10) | 0 | |
Foreign | (8) | 0 | |
Other | 0 | (14) | |
Income tax from continuing operations | 358 | 97 | $ 63 |
Corporate Subsidiaries [Member] | |||
Schedule of Effective Income Tax Rate Reconciliation [Line Items] | |||
Income tax expense (benefit) at U.S. statutory rate of 35 percent | 217 | (166) | |
Nondeductible goodwill | 0 | 241 | |
Nondeductible goodwill included in the Lake Charles LNG Transaction | 105 | 0 | |
State income taxes (net of federal income tax effects) | 9 | 31 | |
Premium on debt retirement | (10) | 0 | |
Foreign | (8) | 0 | |
Other | 0 | (13) | |
Income tax from continuing operations | 313 | 93 | |
Partnership [Member] | |||
Schedule of Effective Income Tax Rate Reconciliation [Line Items] | |||
Income tax expense (benefit) at U.S. statutory rate of 35 percent | 0 | 0 | |
Nondeductible goodwill | 0 | 0 | |
Nondeductible goodwill included in the Lake Charles LNG Transaction | 0 | 0 | |
State income taxes (net of federal income tax effects) | 45 | 5 | |
Premium on debt retirement | 0 | 0 | |
Foreign | 0 | 0 | |
Other | 0 | (1) | |
Income tax from continuing operations | $ 45 | $ 4 |
Income Taxes Tax Effects of Tem
Income Taxes Tax Effects of Temporary Differences (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Deferred income tax assets: | |||
Net operating losses and alternative minimum tax credit | $ 116 | $ 217 | |
Pension and other postretirement benefits | 47 | 57 | |
Long term debt | 53 | 108 | |
Other | 111 | 104 | |
Total deferred income tax assets | 327 | 486 | |
Valuation allowance | (84) | (74) | |
Net deferred income tax assets | 243 | 412 | |
Deferred income tax liabilities: | |||
Properties, plants and equipment | (1,506) | (1,544) | |
Inventory | (153) | (302) | |
Investment in unconsolidated affiliates | (2,528) | (2,244) | |
Trademarks | (355) | (180) | |
Other | (32) | (45) | |
Total deferred income tax liabilities | (4,574) | (4,315) | |
Net deferred income tax liability | (4,331) | (3,903) | $ (3,628) |
Income taxes payable | 85 | 119 | |
Accumulated deferred income taxes | $ (4,246) | $ (3,784) |
Income Taxes Components of Net
Income Taxes Components of Net Deferred Income Tax (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | ||
Net deferred income tax liability, beginning of year | $ (3,903) | $ (3,628) |
Susser acquisition | (488) | 0 |
SUGS Contribution to Regency | 0 | (115) |
Tax provision (including discontinued operations) | 60 | (111) |
Other | 0 | (49) |
Net deferred income tax liability | $ (4,331) | $ (3,903) |
Income Taxes Changes in Unrecog
Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Income Tax Disclosure [Abstract] | |||
Balance at beginning of year | $ 429 | $ 27 | $ 2 |
Unrecognized Tax Benefits, Increases Resulting from Acquisition | 0 | 0 | 28 |
Additions attributable to tax positions taken in the current year | 20 | 0 | 0 |
Additions attributable to tax positions taken in prior years | (1) | 406 | 0 |
Settlements | (5) | 0 | 0 |
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations | (3) | (4) | (3) |
Balance at end of year | $ 440 | $ 429 | $ 27 |
Regulatory Matters, Commitmen94
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Narrative) (Details) $ in Millions | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2012USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2012USD ($) | |
Guarantor Obligations, Current Carrying Value | $ 600 | |||
Debt instrument interest rate | 4.50% | |||
Lease Expiration Date | Dec. 31, 2058 | |||
Rental expense under operating lease | $ 159 | $ 151 | $ 60 | |
Operating Leases, Rent Expense, Sublease Rentals | (26) | (24) | (4) | |
Operating Leases, Rent Expense, Contingent Rentals | $ 24 | 22 | $ 6 | |
Site Contingency, Number of Sites Needing Remediation | 51 | |||
Environmental Costs Recognized, Recovery Credited to Expense | $ 19 | |||
Payments for Environmental Liabilities | 48 | 41 | ||
FGT | ||||
Proceeds from Legal Settlements | $ 100 | |||
Loss Contingency, Damages Awarded, Value | $ 19 | 1 | ||
AmeriGas [Member] | ||||
Business Combination, Contingent Consideration, Liability | $ 1,550 | |||
Southern Union [Member] | ||||
Percentage Of Recovery | 50.00% | |||
Loss Contingency, Estimated Recovery from Third Party | 150,000 | |||
SUGS [Member] | ||||
Environmental Expense and Liabilities | $ 1 | |||
Related To Deductibles [Member] | ||||
Loss Contingency Accrual, at Carrying Value | 37 | $ 46 | ||
Final Judgement [Member] | ||||
Gain Contingency, Unrecorded Amount | 536 | |||
Disgorgement [Member] | ||||
Gain Contingency, Unrecorded Amount | 595 | |||
Expense Reimbursement [Member] | ||||
Gain Contingency, Unrecorded Amount | $ 1 | |||
MTBE Sites [Member] | ||||
Site Contingency, Number of Sites Needing Remediation | 19 | |||
Compensatory Damages [Member] | ||||
Gain Contingency, Unrecorded Amount | $ 319 |
Regulatory Matters, Commitmen95
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Future minimum lease commitments) (Details) $ in Millions | Dec. 31, 2014USD ($) |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
2,015 | $ 151 |
2,016 | 129 |
2,017 | 118 |
2,018 | 108 |
2,019 | 102 |
Thereafter | 829 |
Future Rental Income | $ (34) |
Regulatory Matters, Commitmen96
Regulatory Matters, Commitments, Contingencies and Environmental Matters (Liabilities Related to Environmental Matters) (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
Environmental Remediation Obligations [Abstract] | ||
Accrued Environmental Loss Contingencies, Current | $ 41 | $ 47 |
Accrued Environmental Loss Contingencies, Noncurrent | 360 | 356 |
Accrual for Environmental Loss Contingencies | $ 401 | $ 403 |
Price risk management assets 97
Price risk management assets and liabilties (Outstanding commodity-related derivatives) (Details) | 12 Months Ended | ||
Dec. 31, 2014MMbtubarrelsMegawattbblMW | Dec. 31, 2013MMbtubarrelsMegawattbblMW | ||
Power [Member] | ETP [Member] | Options - Puts [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | Megawatt | (72,000) | (52,800) | |
Maximum Term Of Commodity Derivatives | 2,015 | ||
Natural Gas [Member] | ETP [Member] | Fixed Swaps Futures [Member] | Non Trading [Member] | Fair Value Hedging [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | ||
Natural Gas [Member] | ETP [Member] | Call Option [Member] | Trading [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | ||
Natural Gas [Member] | ETP [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | (9,116,777) | 5,668,559 | |
Maximum Term Of Commodity Derivatives | 2,015 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | 57,500 | 570,000 | |
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value Hedging [Member] | |||
Notional Volume | (39,287,500) | (7,352,500) | |
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Basis Swaps IFERC/NYMEX [Member] | Cash Flow Hedging [Member] | |||
Notional Volume | 0 | (1,825,000) | |
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | (8,779,000) | (8,195,000) | |
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Fixed Swaps Futures [Member] | Fair Value Hedging [Member] | |||
Notional Volume | (39,287,500) | (50,530,000) | |
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Fixed Swaps Futures [Member] | Cash Flow Hedging [Member] | |||
Notional Volume | 0 | (12,775,000) | |
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | 46,150,000 | (9,690,000) | |
Maximum Term Of Commodity Derivatives | 2,015 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Hedged Item - Inventory (MMBtu) [Member] | Fair Value Hedging [Member] | |||
Notional Volume | 39,287,500 | 50,530,000 | |
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Minimum [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Minimum [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Minimum [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Maximum [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | ||
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Maximum [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,016 | 2,015 | |
Non Trading [Member] | Natural Gas [Member] | ETP [Member] | Maximum [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,016 | ||
Non Trading [Member] | Natural Gas [Member] | Regency | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | (25,525,000) | (24,455,000) | |
Maximum Term Of Commodity Derivatives | 2,015 | ||
Non Trading [Member] | Natural Gas [Member] | Regency | Minimum [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Natural Gas [Member] | Regency | Maximum [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | ||
Non Trading [Member] | Propane [Member] | Regency | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | ||
Non Trading [Member] | Propane [Member] | Regency | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | barrels | (29,148,000) | (52,122,000) | |
Non Trading [Member] | Propane [Member] | Regency | Minimum [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Propane [Member] | Regency | Maximum [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | ||
Non Trading [Member] | Crude Oil [Member] | ETP [Member] | Future [Member] | Cash Flow Hedging [Member] | |||
Notional Volume | bbl | 0 | (30,000) | |
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Refined Products [Member] | ETP [Member] | Future [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | barrels | 13,745,755 | (280,000) | |
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Non Trading [Member] | Natural Gas Liquids [Member] | ETP [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | barrels | (2,179,400) | (1,133,600) | |
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Non Trading [Member] | Natural Gas Liquids [Member] | ETP [Member] | Forward Swaps [Member] | Cash Flow Hedging [Member] | |||
Notional Volume | bbl | 0 | (780,000) | |
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | Natural Gas Liquids [Member] | Regency | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Non Trading [Member] | Natural Gas Liquids [Member] | Regency | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | barrels | (292,000) | (438,000) | |
Non Trading [Member] | WTI Crude Oil [Member] | Regency | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,014 | ||
Non Trading [Member] | WTI Crude Oil [Member] | Regency | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | barrels | (1,252,000) | (521,000) | |
Non Trading [Member] | WTI Crude Oil [Member] | Regency | Minimum [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | ||
Non Trading [Member] | WTI Crude Oil [Member] | Regency | Maximum [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,016 | ||
Trading [Member] | Power [Member] | ETP [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | MW | 288,775 | 351,050 | |
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Trading [Member] | Power [Member] | ETP [Member] | Future [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | MW | (156,000) | (772,476) | |
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Trading [Member] | Power [Member] | ETP [Member] | Call Option [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | MW | 198,556 | 103,200 | |
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Trading [Member] | Power [Member] | ETP [Member] | Options - Puts [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,014 | ||
Trading [Member] | Natural Gas [Member] | ETP [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | [1] | (13,907,500) | (487,500) |
Trading [Member] | Natural Gas [Member] | ETP [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | (232,500) | 9,457,500 | |
Maximum Term Of Commodity Derivatives | 2,015 | ||
Trading [Member] | Natural Gas [Member] | ETP [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | 0 | 1,937,500 | |
Trading [Member] | Natural Gas [Member] | ETP [Member] | Call Option [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | 5,000,000 | ||
Trading [Member] | Natural Gas [Member] | ETP [Member] | Minimum [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,015 | 2,014 | |
Trading [Member] | Natural Gas [Member] | ETP [Member] | Minimum [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,014 | ||
Trading [Member] | Natural Gas [Member] | ETP [Member] | Minimum [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,014 | ||
Trading [Member] | Natural Gas [Member] | ETP [Member] | Maximum [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,016 | 2,017 | |
Trading [Member] | Natural Gas [Member] | ETP [Member] | Maximum [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Trading [Member] | Natural Gas [Member] | ETP [Member] | Maximum [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | |||
Maximum Term Of Commodity Derivatives | 2,016 | ||
Trading [Member] | Crude Oil [Member] | ETP [Member] | Future [Member] | Mark to Market Derivatives [Member] | |||
Notional Volume | bbl | 0 | 103,000 | |
Maximum Term Of Commodity Derivatives | 2,014 | ||
[1] | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Price risk management assets 98
Price risk management assets and liabilties (Interest rate swaps outstanding) (Details) - Derivatives not designated as hedging instruments - Interest rate derivatives [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | ||
ETP [Member] | July 2018 [Member] | |||
Type | [1] | Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% | |
Notional amount outstanding | $ 0 | $ 600 | |
ETP [Member] | June 2021 [Member] | |||
Type | [1] | Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% | |
Notional amount outstanding | $ 0 | 400 | |
ETP [Member] | Floating Interest Rate Of 6.70 Percent [Member] | |||
Type | [1] | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | |
Notional amount outstanding | $ 200 | 400 | |
Panhandle [Member] | Fixed Rate of 3.75 Percent [Member] | |||
Type | [1] | Pay a fixed rate of 3.82% and receive a floating rate | |
Notional amount outstanding | $ 0 | 275 | |
Forward-Starting Swaps [Member] | ETP [Member] | July 2014 [Member] | |||
Type | [1],[2] | Forward-starting to pay a fixed rate of 4.25% and receive a floating rate | |
Notional amount outstanding | [2] | $ 0 | 400 |
Forward-Starting Swaps [Member] | ETP [Member] | July 2015 [Member] | |||
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.38% and receive a floating rate | |
Notional amount outstanding | [2] | $ 200 | 0 |
Forward-Starting Swaps [Member] | ETP [Member] | July 2016 [Member] | |||
Type | [1],[3] | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | |
Notional amount outstanding | [3] | $ 200 | 0 |
Forward-Starting Swaps [Member] | ETP [Member] | July 2017 [Member] | |||
Type | [1],[2],[4] | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | |
Notional amount outstanding | [2],[4] | $ 300 | 0 |
Forward-Starting Swaps [Member] | ETP [Member] | July 2018 [Member] | |||
Type | [1],[4] | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | |
Notional amount outstanding | [4] | $ 200 | 0 |
Forward-Starting Swaps [Member] | ETP [Member] | July 2019 [Member] | |||
Type | [1],[4] | Forward-starting to pay a fixed rate of 3.19% and receive a floating rate | |
Notional amount outstanding | [4] | $ 300 | $ 0 |
[1] | (1) Floating rates are based on 3-month LIBOR. | ||
[2] | (2) Represents the effective date. These forward-starting swaps have terms of 10 years with a mandatory termination date the same as the effective date. | ||
[3] | (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] | (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. |
Price risk management assets 99
Price risk management assets and liabilties (Fair Value of Derivative Instruments) (Details) - Credit Derivatives Contract Type [Domain] - Scenario, Unspecified [Domain] - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
Total derivative assets | $ 770 | $ 319 |
Total derivative liabilities | 771 | 388 |
Designated as Hedging Instrument [Member] | ||
Total derivative assets | 43 | 2 |
Total derivative liabilities | 0 | (20) |
Not Designated as Hedging Instrument [Member] | ||
Total derivative assets | 727 | 317 |
Total derivative liabilities | (771) | (368) |
Commodity Derivatives (Margin Deposits) [Member] | Designated as Hedging Instrument [Member] | ||
Total derivative assets | 43 | 2 |
Total derivative liabilities | 0 | (20) |
Commodity Derivatives (Margin Deposits) [Member] | Not Designated as Hedging Instrument [Member] | ||
Total derivative assets | 617 | 227 |
Total derivative liabilities | (577) | (209) |
Commodity [Member] | Not Designated as Hedging Instrument [Member] | ||
Total derivative assets | 107 | 43 |
Total derivative liabilities | (23) | (45) |
Interest Rate Derivatives [Member] | Not Designated as Hedging Instrument [Member] | ||
Total derivative assets | 3 | 47 |
Total derivative liabilities | (155) | (95) |
Embedded Derivatives in Regency Preferred Units [Member] | Not Designated as Hedging Instrument [Member] | ||
Total derivative assets | 0 | 0 |
Total derivative liabilities | $ (16) | $ (19) |
Price risk management assets100
Price risk management assets and liabilties (Netting table) (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 770 | $ 319 |
Derivative Liability, Fair Value, Gross Liability | (771) | (388) |
Derivative Asset, Fair Value, Amount Offset Against Collateral | (14) | (37) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | (3) | 91 |
Netting [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 697 | 306 |
Derivative Liability, Fair Value, Gross Liability | (597) | (356) |
Derivative Asset, Fair Value, Gross Liability | (19) | (36) |
Derivative Liability, Fair Value, Gross Asset | 19 | 36 |
Derivative Asset, Fair Value, Net | 683 | 269 |
Derivative Liability, Fair Value, Net | (600) | (265) |
Asset Fair Value, Netting Offset [Member] | Netting [Member] | ||
Derivative [Line Items] | ||
Payments on Margin Deposits | 5 | (1) |
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value | 87 | 50 |
Liability Fair Value, Netting Offset [Member] | Netting [Member] | ||
Derivative [Line Items] | ||
Payments on Margin Deposits | (22) | 55 |
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value | (171) | (123) |
Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 727 | 317 |
Derivative Liability, Fair Value, Gross Liability | 771 | 368 |
Bi-lateral contracts [Member] | Netting [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 23 | 42 |
Derivative Liability, Fair Value, Gross Liability | (23) | (38) |
Broker cleared derivative contracts [Member] | Netting [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 674 | 264 |
Derivative Liability, Fair Value, Gross Liability | $ (574) | $ (318) |
Price risk management assets101
Price risk management assets and liabilties (Partnership's derivative assets and liabilities, recognized OCI on derivatives (effective portion)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | $ 0 | $ (1) | $ 8 |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | (8) | 8 | 54 |
Commodity [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | 0 | (1) | 8 |
Cost of Sales [Member] | Commodity [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | $ (8) | $ 8 | $ 54 |
Price risk management assets102
Price risk management assets and liabilties (Partnership's derivative assets and liabilities, amount of gain/(loss) reclassified from AOCI into income (effective portion)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | $ 0 | $ (1) | $ 8 |
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | (3) | 4 | 14 |
Amount of Gain (Loss) Recognized in Income on Ineffective Portion | (8) | 8 | 54 |
Amount of Gain (Loss) Recognized In Income On Derivatives | 39 | 24 | (12) |
Gains (losses) on interest rate derivatives | (157) | 44 | (4) |
Commodity [Member] | |||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | 0 | (1) | 8 |
Commodity [Member] | Cost of Sales [Member] | |||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | (3) | 4 | 14 |
Amount of Gain (Loss) Recognized in Income on Ineffective Portion | (8) | 8 | 54 |
Interest Rate Derivatives [Member] | Gains (Losses) On Non-Hedged Interest Rate Derivatives [Member] | |||
Amount of Gain (Loss) Recognized In Income On Derivatives | (157) | 53 | (19) |
Embedded Derivatives in Regency Preferred Units [Member] | Other Income (Expenses) [Member] | |||
Amount of Gain (Loss) Recognized In Income On Derivatives | 3 | 6 | 14 |
Trading [Member] | Commodity [Member] | Cost of Sales [Member] | |||
Amount of Gain (Loss) Recognized In Income On Derivatives | (6) | (11) | (7) |
Non Trading [Member] | Commodity [Member] | Cost of Sales [Member] | |||
Amount of Gain (Loss) Recognized In Income On Derivatives | 199 | (21) | 26 |
Non Trading [Member] | Commodity [Member] | Deferred Gas Purchases [Member] | |||
Amount of Gain (Loss) Recognized In Income On Derivatives | $ 0 | $ (3) | $ (26) |
Retirement Benefits (Narratives
Retirement Benefits (Narratives) (Details) - Plan Asset Categories [Domain] - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted average grant-date fair value per unit award granted | $ 60.85 | $ 50.54 | $ 43.93 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 5.4 | ||
Unvested unit awards outstanding | 3.6 | 3.2 | |
Gain on curtailment of other postretirement benefits | $ 0 | $ 0 | $ 15 |
Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Large Cap US Equitiies | 100.00% | 41.00% | |
Fixed Income Securities | 45.00% | ||
Other Investments - Plan Asset Allocation | 14.00% | ||
2,015 | $ 129 | ||
Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Large Cap US Equitiies | 56.00% | ||
Fixed Income Securities | 38.00% | ||
Cash Fund Investments | 6.00% | ||
ETP [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Contributions to the 401(k) savings plan | $ 59 | $ 47 | $ 30 |
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Large Cap US Equitiies | 41.00% | ||
Fixed Income Securities | 48.00% | ||
Cash Fund Investments | 6.00% | ||
Other Investments - Plan Asset Allocation | 5.00% | ||
Sunoco [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent | 200 | ||
Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
2,015 | $ 10 | ||
Sunoco Logistics Unit-Based Compensation Plans [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Awards remaining unvested weighted average period, in years | 2 years 11 months | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 0.7 | ||
Unvested unit awards outstanding | 1.5 |
Retirement Benefits Obligations
Retirement Benefits Obligations and Funded Status (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | $ 0 | $ 3 | |
Interest cost | 31 | 35 | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Defined Benefit Plan, Amounts Recognized in Balance Sheet | (32) | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | (86) | ||
Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 0 | 0 | |
Interest cost | 5 | 6 | |
Defined Benefit Plan, Plan Amendments | 1 | 2 | |
Actuarial Loss and Other | 2 | (14) | |
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | 0 | 0 | |
Change in Plan Assets, Dispositions | (5) | (27) | |
Change in Benefit Obligations, Dispositions | (1) | (41) | |
Defined Benefit Plan, Actual Return on Plan Assets | 6 | 17 | |
Defined Benefit Plan, Contributions by Employer | 8 | 8 | |
Benefit obligation | 202 | 223 | $ 296 |
Fair value of plan assets | 265 | 284 | 312 |
Amount underfunded | (63) | (61) | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Non-current assets | 90 | 86 | |
Current liabilities | (2) | (2) | |
Non-current liabilities | (25) | (23) | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet | 63 | 61 | |
Defined Benefit Plan, Amortization of Net Gains (Losses) | (20) | (25) | |
Defined Benefit Plan, Benefits Paid | 28 | 26 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax | 17 | 18 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | (3) | (7) | |
Southern Union [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 598 | 600 | |
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 265 | 284 | |
Funded Plans [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 0 | ||
Interest cost | 28 | 33 | |
Defined Benefit Plan, Plan Amendments | 0 | 0 | |
Actuarial Loss and Other | 130 | (74) | |
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | (27) | (95) | |
Change in Plan Assets, Dispositions | 0 | (155) | |
Change in Benefit Obligations, Dispositions | 0 | (253) | |
Defined Benefit Plan, Actual Return on Plan Assets | 70 | 43 | |
Defined Benefit Plan, Contributions by Employer | 0 | 0 | |
Benefit obligation | 718 | 632 | 1,117 |
Fair value of plan assets | 598 | 600 | 906 |
Amount underfunded | 120 | 32 | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Non-current assets | 0 | 0 | |
Current liabilities | 0 | 0 | |
Non-current liabilities | (120) | (32) | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet | (120) | ||
Defined Benefit Plan, Amortization of Net Gains (Losses) | 18 | (86) | |
Defined Benefit Plan, Benefits Paid | 45 | 99 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax | 0 | 0 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 18 | ||
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 0 | 0 | |
Interest cost | 3 | 2 | |
Defined Benefit Plan, Plan Amendments | 0 | 0 | |
Actuarial Loss and Other | 10 | (3) | |
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | 0 | 0 | |
Change in Benefit Obligations, Dispositions | 0 | 0 | |
Benefit obligation | 65 | 61 | 78 |
Amount underfunded | 65 | 61 | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Non-current assets | 0 | 0 | |
Current liabilities | (9) | (9) | |
Non-current liabilities | (56) | (52) | |
Defined Benefit Plan, Amounts Recognized in Balance Sheet | (65) | (61) | |
Defined Benefit Plan, Amortization of Net Gains (Losses) | 7 | (4) | |
Defined Benefit Plan, Benefits Paid | 9 | 16 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax | 0 | 0 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 7 | (4) | |
Change in Plan Assets [Member] | Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | 0 | 0 | |
Change in Plan Assets, Dispositions | 0 | 0 | |
Defined Benefit Plan, Actual Return on Plan Assets | 0 | 0 | |
Defined Benefit Plan, Contributions by Employer | 0 | 0 | |
Fair value of plan assets | 0 | 0 | $ 0 |
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | |||
Defined Benefit Plan, Benefits Paid | $ 0 | $ 0 |
Retirement Benefits Components
Retirement Benefits Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | $ 0 | $ 3 |
Interest cost | 31 | 35 |
Expected return on plan assets | (40) | (54) |
Prior service cost amortization | 0 | 0 |
Actuarial loss amortization | 1 | (2) |
Settlements | 4 | 2 |
Net periodic benefit cost subtotal | (14) | (16) |
Regulatory adjustment(1) | 0 | 5 |
Net periodic benefit cost | (14) | (11) |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 0 | 0 |
Interest cost | 5 | 6 |
Expected return on plan assets | (8) | (9) |
Prior service cost amortization | 1 | 1 |
Actuarial loss amortization | 1 | 0 |
Settlements | 0 | 0 |
Net periodic benefit cost subtotal | (3) | (2) |
Regulatory adjustment(1) | 0 | 0 |
Net periodic benefit cost | (3) | (2) |
Funded Plans [Member] | Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 0 | |
Interest cost | $ 28 | $ 33 |
Retirement Benefits Summary for
Retirement Benefits Summary for Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation | $ 202 | $ 223 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | 265 | 284 |
Funded Plans [Member] | Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation | 718 | 632 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation | 718 | 632 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | 598 | 600 |
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation | 65 | 61 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation | 65 | 61 |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | $ 0 | $ 0 |
Retirement Benefits Weighted-Av
Retirement Benefits Weighted-Average Assumptions Used in Determining Benefit Obligations (Details) | Dec. 31, 2014 | Dec. 31, 2013 |
Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 3.62% | 4.65% |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 2.24% | 2.33% |
Retirement Benefits Assumed Hea
Retirement Benefits Assumed Health Care Cost Trend Rates (Details) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 7.09% | 7.57% |
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.41% | 5.42% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2,018 | 2,018 |
Retirement Benefits Schedule Of
Retirement Benefits Schedule Of Weighted-Average Assumptions To Determine Defined Benefit Plans And Postretirement Benefit Plans Expense (Details) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.65% | 3.50% |
Expected long term return on assets, tax exempt accounts | 7.50% | 7.50% |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.02% | 2.68% |
Expected long term return on assets, tax exempt accounts | 7.00% | 6.95% |
Expected long term return on assets, taxable accounts | 4.50% | 4.42% |
Retirement Benefits Fair Value
Retirement Benefits Fair Value of Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | $ 265 | $ 284 | $ 312 | |
Large Cap US Equitiies | 56.00% | |||
Fixed Income Securities | 38.00% | |||
Cash Fund Investments | 6.00% | |||
Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Large Cap US Equitiies | 100.00% | 41.00% | ||
Fixed Income Securities | 45.00% | |||
Other Investments - Plan Asset Allocation | 14.00% | |||
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | $ 9 | |||
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 25 | |||
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 131 | |||
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 110 | |||
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 125 | |||
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 463 | |||
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 265 | $ 284 | ||
Large Cap US Equitiies | 41.00% | |||
Fixed Income Securities | 48.00% | |||
Cash Fund Investments | 6.00% | |||
Other Investments - Plan Asset Allocation | 5.00% | |||
Southern Union [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 598 | $ 600 | ||
Southern Union [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 9 | 10 | ||
Southern Union [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 25 | 12 | ||
Southern Union [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | [1] | 131 | 130 | |
Southern Union [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | [2] | 110 | 368 | |
Southern Union [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 125 | 144 | ||
Southern Union [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 463 | 220 | ||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 140 | 122 | ||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 25 | 12 | ||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 10 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 12 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 112 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 125 | 162 | ||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 573 | 501 | ||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 18 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 281 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 144 | |||
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 220 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | $ 0 | 87 | ||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 87 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | 0 | |||
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Fair value of plan assets | $ 0 | |||
[1] | (1) Primarily comprised of approximately 56% equities, 38% fixed income securities and 6% cash as of December 31, 2014. | |||
[2] | (1) Primarily comprised of approximately 100% equities as of December 31, 2014. |
Retirement Benefits Expected Fu
Retirement Benefits Expected Future Benefit Payments (Details) $ in Millions | Dec. 31, 2014USD ($) |
Pension Plans, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | $ 129 |
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | 28 |
2,016 | 26 |
2,017 | 25 |
2,018 | 23 |
2,019 | 22 |
2020 - 2024 | 65 |
Other Postretirement Benefit Plans, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | 10 |
Funded Plans [Member] | Pension Plans, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | 717 |
2,016 | 0 |
2,017 | 0 |
2,018 | 0 |
2,019 | 0 |
2020 - 2024 | 0 |
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,015 | 9 |
2,016 | 8 |
2,017 | 7 |
2,018 | 7 |
2,019 | 6 |
2020 - 2024 | $ 23 |
Related Party Transactions (Nar
Related Party Transactions (Narrative) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2014USD ($) | |
Related Party Transaction, Amounts of Transaction | $ 75 |
Related Party Transactions Rela
Related Party Transactions Related Party - Affiliated Revenues (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Related Party Transaction [Line Items] | |||
Affiliated revenues | $ 965 | $ 1,442 | $ 188 |
Related Party Transactions R114
Related Party Transactions Related Party - Affiliate AR and Affiliate AP (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Dec. 31, 2013 |
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | $ 139 | $ 117 |
Accounts Payable, Related Parties, Current | 25 | 25 |
ETE | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 11 | 18 |
Accounts Payable, Related Parties, Current | 0 | 10 |
Dakota Access Pipeline | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 68 | 0 |
PES | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 6 | 7 |
FGT | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 9 | 29 |
Accounts Payable, Related Parties, Current | 2 | 8 |
ET Crude Oil | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 10 | 24 |
Lake Charles LNG | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 3 | 0 |
Accounts Payable, Related Parties, Current | 2 | 0 |
Other | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 32 | 39 |
Accounts Payable, Related Parties, Current | $ 21 | $ 7 |
Reportable Segments (Financial
Reportable Segments (Financial information by segment) (Details) - Segments [Domain] - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Segment Adjusted EBITDA | $ 5,710 | $ 4,404 | $ 3,139 | ||||||||
Depreciation, depletion and amortization | (1,669) | (1,296) | (858) | ||||||||
Interest expense, net of interest capitalized | (1,165) | (1,013) | (788) | ||||||||
Gain on deconsolidation of Propane Business | 0 | 0 | 1,057 | ||||||||
Gain on sale of AmeriGas common units | 177 | 87 | 0 | ||||||||
Goodwill impairment | (370) | (689) | 0 | ||||||||
Gains (losses) on interest rate derivatives | (157) | 44 | (4) | ||||||||
Non-cash unit-based compensation expense | (68) | (54) | (47) | ||||||||
Unrealized gains (losses) on commodity risk management activities | 112 | 42 | 2 | ||||||||
Inventory valuation adjustments | (473) | 3 | (75) | ||||||||
Loss on extinguishment of debt | (25) | (7) | (124) | ||||||||
Non-operating environmental remediation | 0 | 168 | 0 | ||||||||
Adjusted EBITDA related to discontinued operations | (27) | (76) | (99) | ||||||||
Adjusted EBITDA related to unconsolidated affiliates | (748) | (722) | (646) | ||||||||
Equity in earnings of unconsolidated affiliates | 332 | 236 | 212 | ||||||||
Other, net | (36) | 19 | 48 | ||||||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 1,593 | 810 | 1,817 | ||||||||
Revenues | $ 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | $ 12,607 | $ 12,486 | $ 12,063 | $ 11,179 | 55,475 | 48,335 | 16,964 |
Cost of products sold | 48,389 | 42,554 | 13,088 | ||||||||
Assets | 62,674 | 49,900 | 62,674 | 49,900 | 48,394 | ||||||
Property, Plant and Equipment, Additions | 5,494 | 3,327 | 3,533 | ||||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 3,760 | 4,050 | 3,760 | 4,050 | 4,768 | ||||||
Intrastate Transportation And Storage [Member] | |||||||||||
Segment Adjusted EBITDA | 559 | 521 | 667 | ||||||||
Depreciation, depletion and amortization | (125) | (122) | (122) | ||||||||
Goodwill impairment | 0 | 0 | |||||||||
Equity in earnings of unconsolidated affiliates | 27 | 30 | 33 | ||||||||
Revenues | 2,857 | 2,452 | 2,191 | ||||||||
Cost of products sold | 2,169 | 1,737 | 1,394 | ||||||||
Assets | 4,984 | 5,048 | 4,984 | 5,048 | 5,340 | ||||||
Property, Plant and Equipment, Additions | 169 | 47 | 37 | ||||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 423 | 443 | 423 | 443 | 652 | ||||||
Interstate Transportation and Storage [Member] | |||||||||||
Segment Adjusted EBITDA | 1,212 | 1,368 | 1,117 | ||||||||
Depreciation, depletion and amortization | (203) | (244) | (209) | ||||||||
Goodwill impairment | 0 | ||||||||||
Equity in earnings of unconsolidated affiliates | 196 | 182 | 162 | ||||||||
Revenues | 1,072 | 1,309 | 1,109 | ||||||||
Assets | 10,779 | 11,537 | 10,779 | 11,537 | 12,376 | ||||||
Property, Plant and Equipment, Additions | 411 | 152 | 133 | ||||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 2,649 | 2,588 | 2,649 | 2,588 | 2,723 | ||||||
Midstream [Member] | |||||||||||
Segment Adjusted EBITDA | 1,349 | 766 | 613 | ||||||||
Depreciation, depletion and amortization | (569) | (335) | (277) | ||||||||
Goodwill impairment | 0 | ||||||||||
Equity in earnings of unconsolidated affiliates | 10 | 1 | (10) | ||||||||
Revenues | 6,823 | 4,276 | 3,077 | ||||||||
Cost of products sold | 4,893 | 3,130 | 2,120 | ||||||||
Assets | 15,562 | 7,847 | 15,562 | 7,847 | 7,189 | ||||||
Property, Plant and Equipment, Additions | 1,298 | 1,114 | 1,633 | ||||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 138 | 36 | 138 | 36 | 36 | ||||||
NGL Transportation And Services [Member] | |||||||||||
Segment Adjusted EBITDA | 591 | 350 | 209 | ||||||||
Depreciation, depletion and amortization | (113) | (91) | (53) | ||||||||
Goodwill impairment | 0 | 0 | |||||||||
Equity in earnings of unconsolidated affiliates | (3) | (2) | 2 | ||||||||
Revenues | 3,911 | 2,126 | 650 | ||||||||
Cost of products sold | 3,166 | 1,654 | 361 | ||||||||
Assets | 4,568 | 4,321 | 4,568 | 4,321 | 3,742 | ||||||
Property, Plant and Equipment, Additions | 427 | 448 | 1,306 | ||||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 31 | 29 | 31 | 29 | 29 | ||||||
Investment in Sunoco Logistics [Member] | |||||||||||
Segment Adjusted EBITDA | 971 | 871 | 219 | ||||||||
Depreciation, depletion and amortization | (296) | (265) | (63) | ||||||||
Goodwill impairment | 0 | 0 | |||||||||
Equity in earnings of unconsolidated affiliates | 23 | 18 | 5 | ||||||||
Revenues | 18,088 | 16,639 | 3,189 | ||||||||
Cost of products sold | 17,110 | 15,574 | 2,885 | ||||||||
Assets | 13,619 | 11,650 | 13,619 | 11,650 | 10,291 | ||||||
Property, Plant and Equipment, Additions | 2,510 | 1,018 | 139 | ||||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 226 | 125 | 226 | 125 | 118 | ||||||
Retail Marketing [Member] | |||||||||||
Segment Adjusted EBITDA | 731 | 325 | 109 | ||||||||
Depreciation, depletion and amortization | (189) | (114) | (28) | ||||||||
Goodwill impairment | 0 | 0 | |||||||||
Equity in earnings of unconsolidated affiliates | 2 | 2 | 1 | ||||||||
Revenues | 22,487 | 21,012 | 5,926 | ||||||||
Cost of products sold | 21,154 | 20,150 | 5,757 | ||||||||
Assets | 8,930 | 3,936 | 8,930 | 3,936 | 3,926 | ||||||
Property, Plant and Equipment, Additions | 259 | 176 | 58 | ||||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 19 | 22 | 19 | 22 | 21 | ||||||
Other Segments [Member] | |||||||||||
Segment Adjusted EBITDA | 297 | 203 | 205 | ||||||||
Depreciation, depletion and amortization | (174) | (125) | (106) | ||||||||
Goodwill impairment | 0 | 0 | |||||||||
Equity in earnings of unconsolidated affiliates | 77 | 5 | 19 | ||||||||
Revenues | 3,331 | 2,597 | 1,762 | ||||||||
Cost of products sold | 2,975 | 2,337 | 1,511 | ||||||||
Assets | 4,232 | 5,561 | 4,232 | 5,561 | 5,530 | ||||||
Property, Plant and Equipment, Additions | 420 | 372 | 227 | ||||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | $ 274 | $ 807 | 274 | 807 | 1,189 | ||||||
Intersegment Eliminations [Member] | |||||||||||
Revenues | (3,094) | (2,076) | (940) | ||||||||
Cost of products sold | $ (3,078) | $ (2,028) | $ (940) |
Reportable Segments Narrative (
Reportable Segments Narrative (Details) | 6 Months Ended |
Jun. 30, 2015 | |
Lone Star L.L.C. [Member] | Regency | Regency Merger [Member] | |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 30.00% |
Quarterly Financial Data (Detai
Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Revenues | $ 13,427 | $ 14,933 | $ 14,088 | $ 13,027 | $ 12,607 | $ 12,486 | $ 12,063 | $ 11,179 | $ 55,475 | $ 48,335 | $ 16,964 |
Gross profit | 1,845 | 1,919 | 1,737 | 1,585 | 1,490 | 1,422 | 1,497 | 1,372 | 7,086 | 5,781 | |
Operating income | 159 | 809 | 769 | 706 | (138) | 545 | 671 | 541 | 2,443 | 1,619 | 1,425 |
Net income | (245) | 513 | 548 | 483 | (482) | 415 | 411 | 402 | 1,299 | 746 | 1,645 |
Common Unitholders’ interest in net income (loss) | $ (90) | $ 148 | $ 295 | $ 253 | $ (666) | $ 209 | $ 165 | $ 194 | $ 606 | $ (98) | $ 1,108 |
Basic net income (loss) per Common Unit | $ (0.28) | $ 0.44 | $ 0.92 | $ 0.76 | $ (1.90) | $ 0.55 | $ 0.53 | $ 0.63 | $ 1.77 | $ (0.18) | $ 4.43 |
Diluted net income (loss) per Common Unit | $ (0.28) | $ 0.44 | $ 0.92 | $ 0.76 | $ (1.90) | $ 0.55 | $ 0.53 | $ 0.63 | $ 1.77 | $ (0.18) | $ 4.42 |
ETP [Member] | |||||||||||
Revenues | $ 51,158 | $ 46,339 | $ 15,702 | ||||||||
Net income | 1,553 | 767 | 1,647 | ||||||||
Regency | |||||||||||
Revenues | 4,840 | 2,242 | 1,309 | ||||||||
Net income | $ (142) | $ 64 | $ 48 |
Quarterly Financial Data Quarte
Quarterly Financial Data Quarterly Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Inventory Valuation Reserves | $ 456 | $ 456 | |||
Goodwill impairment | 370 | $ 689 | $ 0 | ||
Excess of distribution made above net income | $ 544 | $ 1,120 | |||
Regency | |||||
Goodwill impairment | $ 370 |
Uncategorized Items - ete-20150
Label | Element | Value |
Cash [Member] | Other Postretirement Benefit Plan [Member] | Southern Union [Member] | ||
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum | ete_DefinedBenefitPlanTargetAllocationPercentageCashMaximum | 10.00% |
Equity [Member] | Other Postretirement Benefit Plan [Member] | Southern Union [Member] | ||
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum | 35.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMinimum | 25.00% |
Fixed Income Investments [Member] | Other Postretirement Benefit Plan [Member] | Southern Union [Member] | ||
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMaximum | 75.00% |
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | us-gaap_DefinedBenefitPlanTargetPlanAssetAllocationsRangeMinimum | 65.00% |
External Customers [Member] | Other Segments [Member] | ||
Revenues | us-gaap_Revenues | $ 1,322 |
Revenues | us-gaap_Revenues | 2,094 |
Revenues | us-gaap_Revenues | 2,869 |
External Customers [Member] | Interstate Transportation and Storage [Member] | ||
Revenues | us-gaap_Revenues | 1,057 |
Revenues | us-gaap_Revenues | 1,109 |
Revenues | us-gaap_Revenues | 1,270 |
External Customers [Member] | Intrastate Transportation And Storage [Member] | ||
Revenues | us-gaap_Revenues | 2,010 |
Revenues | us-gaap_Revenues | 2,242 |
Revenues | us-gaap_Revenues | 2,645 |
External Customers [Member] | Investment in Sunoco Logistics [Member] | ||
Revenues | us-gaap_Revenues | 16,480 |
Revenues | us-gaap_Revenues | 17,920 |
Revenues | us-gaap_Revenues | 3,109 |
External Customers [Member] | Liquids Transportation And Services [Member] | ||
Revenues | us-gaap_Revenues | 2,025 |
Revenues | us-gaap_Revenues | 3,730 |
Revenues | us-gaap_Revenues | 619 |
External Customers [Member] | Midstream [Member] | ||
Revenues | us-gaap_Revenues | 2,869 |
Revenues | us-gaap_Revenues | 3,220 |
Revenues | us-gaap_Revenues | 4,770 |
External Customers [Member] | Retail Marketing [Member] | ||
Revenues | us-gaap_Revenues | 21,004 |
Revenues | us-gaap_Revenues | 22,484 |
Revenues | us-gaap_Revenues | 5,926 |
Intersegment [Member] | Other Segments [Member] | ||
Revenues | us-gaap_Revenues | 440 |
Revenues | us-gaap_Revenues | 462 |
Revenues | us-gaap_Revenues | 503 |
Intersegment [Member] | Interstate Transportation and Storage [Member] | ||
Revenues | us-gaap_Revenues | 0 |
Revenues | us-gaap_Revenues | 15 |
Revenues | us-gaap_Revenues | 39 |
Intersegment [Member] | Intrastate Transportation And Storage [Member] | ||
Revenues | us-gaap_Revenues | 181 |
Revenues | us-gaap_Revenues | 210 |
Revenues | us-gaap_Revenues | 212 |
Intersegment [Member] | Investment in Sunoco Logistics [Member] | ||
Revenues | us-gaap_Revenues | 159 |
Revenues | us-gaap_Revenues | 168 |
Revenues | us-gaap_Revenues | 80 |
Intersegment [Member] | Liquids Transportation And Services [Member] | ||
Revenues | us-gaap_Revenues | 101 |
Revenues | us-gaap_Revenues | 181 |
Revenues | us-gaap_Revenues | 31 |
Intersegment [Member] | Midstream [Member] | ||
Revenues | us-gaap_Revenues | 1,056 |
Revenues | us-gaap_Revenues | 2,053 |
Revenues | us-gaap_Revenues | 208 |
Intersegment [Member] | Retail Marketing [Member] | ||
Revenues | us-gaap_Revenues | 0 |
Revenues | us-gaap_Revenues | 3 |
Revenues | us-gaap_Revenues | $ 8 |