Document_And_Entity_Informatio
Document And Entity Information | 6 Months Ended | |
Jun. 30, 2014 | Aug. 01, 2014 | |
Document Information [Abstract] | ' | ' |
Document Type | '10-Q | ' |
Amendment Flag | 'false | ' |
Document Period End Date | 30-Jun-14 | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q2 | ' |
Entity Information [Abstract] | ' | ' |
Entity Registrant Name | 'Energy Transfer Partners, L.P. | ' |
Entity Central Index Key | '0001012569 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Entity Common Stock, Shares Outstanding | ' | 325,444,109 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
CURRENT ASSETS: | ' | ' |
Cash and cash equivalents | $1,120 | $549 |
Accounts receivable, net | 3,983 | 3,359 |
Accounts receivable from related companies | 255 | 165 |
Inventories | 1,496 | 1,765 |
Exchanges receivable | 81 | 56 |
Price risk management assets | 12 | 35 |
Other current assets | 266 | 310 |
Total current assets | 7,213 | 6,239 |
PROPERTY, PLANT AND EQUIPMENT | 29,379 | 28,430 |
ACCUMULATED DEPRECIATION | -2,888 | -2,483 |
Property, plant and equipment, net | 26,491 | 25,947 |
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 3,850 | 4,436 |
NON-CURRENT PRICE RISK MANAGEMENT ASSETS | 0 | 17 |
GOODWILL | 4,521 | 4,729 |
INTANGIBLE ASSETS, net | 1,512 | 1,568 |
OTHER NON-CURRENT ASSETS, net | 636 | 766 |
Total assets | 44,223 | 43,702 |
CURRENT LIABILITIES: | ' | ' |
Accounts payable | 4,070 | 3,627 |
Accounts payable to related companies | 88 | 45 |
Exchanges payable | 271 | 285 |
Price risk management liabilities | 58 | 45 |
Accrued and other current liabilities | 1,682 | 1,428 |
Current maturities of long-term debt | 1,346 | 637 |
Total current liabilities | 7,515 | 6,067 |
LONG-TERM DEBT, less current maturities | 16,220 | 16,451 |
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES | 69 | 54 |
DEFERRED INCOME TAXES | 3,612 | 3,762 |
OTHER NON-CURRENT LIABILITIES | 1,037 | 1,080 |
COMMITMENTS AND CONTINGENCIES (Note 13) | ' | ' |
REDEEMABLE NONCONTROLLING INTERESTS | 15 | 0 |
EQUITY: | ' | ' |
General Partner | 171 | 171 |
Limited Partners: | ' | ' |
Common Unitholders | 9,089 | 9,797 |
Class H Unitholder | 1,504 | 1,511 |
Accumulated other comprehensive income | 52 | 61 |
Total partners’ capital | 10,816 | 11,540 |
Noncontrolling interest | 4,939 | 4,748 |
Total equity | 15,755 | 16,288 |
Total liabilities and equity | $44,223 | $43,702 |
Consolidated_Statements_Of_Ope
Consolidated Statements Of Operations (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
REVENUES: | ' | ' | ' | ' |
Natural gas sales | $908 | $691 | $2,011 | $1,565 |
NGL sales | 1,015 | 588 | 1,966 | 1,177 |
Crude sales | 4,432 | 3,992 | 8,525 | 7,193 |
Gathering, transportation and other fees | 601 | 692 | 1,256 | 1,329 |
Refined product sales | 4,938 | 4,650 | 9,416 | 9,312 |
Other | 1,135 | 938 | 2,087 | 1,829 |
Total revenues | 13,029 | 11,551 | 25,261 | 22,405 |
COSTS AND EXPENSES: | ' | ' | ' | ' |
Cost of products sold | 11,636 | 10,229 | 22,502 | 19,823 |
Operating expenses | 308 | 327 | 627 | 654 |
Depreciation and amortization | 268 | 251 | 534 | 511 |
Selling, general and administrative | 81 | 112 | 174 | 251 |
Total costs and expenses | 12,293 | 10,919 | 23,837 | 21,239 |
OPERATING INCOME | 736 | 632 | 1,424 | 1,166 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense, net of interest capitalized | -217 | -211 | -436 | -422 |
Equity in earnings of unconsolidated affiliates | 57 | 37 | 136 | 109 |
Gain on sale of AmeriGas common units | 93 | 0 | 163 | 0 |
Gains (losses) on interest rate derivatives | -46 | 39 | -48 | 46 |
Other, net | -14 | -4 | -17 | -1 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 609 | 493 | 1,222 | 898 |
Income tax expense from continuing operations | 70 | 89 | 216 | 92 |
INCOME FROM CONTINUING OPERATIONS | 539 | 404 | 1,006 | 806 |
Income from discontinued operations | 42 | 9 | 66 | 31 |
NET INCOME | 581 | 413 | 1,072 | 837 |
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | 110 | 93 | 186 | 195 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 471 | 320 | 886 | 642 |
GENERAL PARTNER’S INTEREST IN NET INCOME | 125 | 155 | 238 | 283 |
CLASS H UNITHOLDER’S INTEREST IN NET INCOME | 51 | 0 | 100 | 0 |
COMMON UNITHOLDERS’ INTEREST IN NET INCOME | $295 | $165 | $548 | $359 |
INCOME FROM CONTINUING OPERATIONS PER COMMON UNIT: | ' | ' | ' | ' |
Basic | $0.79 | $0.52 | $1.47 | $1.04 |
Diluted | $0.79 | $0.52 | $1.47 | $1.04 |
NET INCOME PER COMMON UNIT: | ' | ' | ' | ' |
Basic | $0.92 | $0.53 | $1.67 | $1.08 |
Diluted | $0.92 | $0.53 | $1.67 | $1.08 |
Consolidated_Statements_Of_Com
Consolidated Statements Of Comprehensive Income (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Statement of Comprehensive Income [Abstract] | ' | ' | ' | ' |
Net income | $581 | $413 | $1,072 | $837 |
Other comprehensive income (loss), net of tax: | ' | ' | ' | ' |
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges | 2 | -1 | 6 | -2 |
Change in value of derivative instruments accounted for as cash flow hedges | -2 | 6 | -6 | 8 |
Change in value of available-for-sale securities | 0 | -1 | 0 | 0 |
Actuarial gain (loss) relating to pension and other postretirement benefits | 0 | 2 | -1 | 1 |
Foreign currency translation adjustment | 1 | 0 | -2 | -1 |
Change in other comprehensive income from unconsolidated affiliates | 1 | -3 | -6 | 4 |
Total other comprehensive income (loss) | 2 | 3 | -9 | 10 |
Comprehensive income | 583 | 416 | 1,063 | 847 |
Less: Comprehensive income attributable to noncontrolling interest | 110 | 91 | 186 | 192 |
Comprehensive income attributable to partners | $473 | $325 | $877 | $655 |
Consolidated_Statement_Of_Equi
Consolidated Statement Of Equity (USD $) | Total | General Partner | Common Units | Class H Units | Accumulated Other Comprehensive Income | Noncontrolling Interest |
In Millions | ||||||
Balance, December 31, 2013 at Dec. 31, 2013 | $16,288 | $171 | $9,797 | $1,511 | $61 | $4,748 |
Distributions to partners | -943 | -238 | -602 | -103 | 0 | 0 |
Distributions to noncontrolling interest | -157 | 0 | 0 | 0 | 0 | -157 |
Units issued for cash | 484 | 0 | 484 | 0 | 0 | 0 |
Subsidiary units issued for cash | 102 | 0 | 14 | 0 | 0 | 88 |
Capital contributions from noncontrolling interest | 71 | 0 | 0 | 0 | 0 | 71 |
Trunkline LNG Transaction (see Note 2) | -1,167 | 0 | -1,167 | 0 | 0 | 0 |
Other comprehensive loss, net of tax | -9 | 0 | 0 | 0 | -9 | 0 |
Other, net | 14 | 0 | 15 | -4 | 0 | 3 |
Net income | 1,072 | 238 | 548 | 100 | 0 | 186 |
Balance, June 30, 2014 at Jun. 30, 2014 | $15,755 | $171 | $9,089 | $1,504 | $52 | $4,939 |
Consolidated_Statements_Of_Cas
Consolidated Statements Of Cash Flows (USD $) | 6 Months Ended | |
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 |
CASH FLOWS FROM OPERATING ACTIVITIES: | ' | ' |
Net income | $1,072 | $837 |
Reconciliation of net income to net cash provided by operating activities: | ' | ' |
Depreciation and amortization | 534 | 511 |
Deferred income taxes | -111 | 73 |
Amortization included in interest expense | -34 | -47 |
LIFO valuation adjustments | -34 | -16 |
Non-cash compensation expense | 27 | 24 |
Gain on sale of AmeriGas common units | -163 | 0 |
Distributions on unvested awards | -8 | -6 |
Equity in earnings of unconsolidated affiliates | -136 | -109 |
Distributions from unconsolidated affiliates | 108 | 154 |
Other non-cash | -33 | 20 |
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 3) | 351 | -277 |
Net cash provided by operating activities | 1,573 | 1,164 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ' | ' |
Cash proceeds from SUGS Contribution (see Note 2) | 0 | 493 |
Cash paid for Holdco Acquisition | 0 | -1,332 |
Cash paid for all other acquisitions | -196 | -5 |
Cash proceeds from the sale of AmeriGas common units | 759 | 0 |
Capital expenditures (excluding allowance for equity funds used during construction) | -1,700 | -1,131 |
Contributions in aid of construction costs | 25 | 11 |
Contributions to unconsolidated affiliates | -63 | -1 |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 65 | 43 |
Proceeds from sale of discontinued operations | 79 | 0 |
Proceeds from the sale of assets | 12 | 19 |
Other | 7 | -25 |
Net cash used in investing activities | -1,012 | -1,928 |
CASH FLOWS FROM FINANCING ACTIVITIES: | ' | ' |
Proceeds from borrowings | 2,993 | 3,960 |
Repayments of long-term debt | -2,544 | -2,832 |
Repayments of borrowings from affiliates | 0 | -166 |
Net proceeds from issuance of Common Units | 484 | 1,090 |
Subsidiary equity offerings, net of issue costs | 102 | 0 |
Capital contributions received from noncontrolling interest | 84 | 72 |
Distributions to partners | -943 | -873 |
Distributions to noncontrolling interest | -157 | -247 |
Debt issuance costs | -9 | -19 |
Net cash provided by financing activities | 10 | 985 |
INCREASE IN CASH AND CASH EQUIVALENTS | 571 | 221 |
CASH AND CASH EQUIVALENTS, beginning of period | 549 | 311 |
CASH AND CASH EQUIVALENTS, end of period | $1,120 | $532 |
Operations_And_Organization
Operations And Organization | 6 Months Ended | |
Jun. 30, 2014 | ||
Operations And Organization [Abstract] | ' | |
Operations And Organization | ' | |
OPERATIONS AND ORGANIZATION: | ||
Energy Transfer Partners, L.P., a publicly traded Delaware master limited partnership, and its subsidiaries (collectively, the “Partnership,” “we” or “ETP”) are managed by ETP’s 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. | ||
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 a 70% interest in 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. | |
• | Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco. Panhandle and Sunoco 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 2, 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 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 retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and its wholly-owned subsidiary, Sunoco. | |
• | Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets. | |
Our financial statements reflect the following reportable business segments: | ||
•intrastate transportation and storage; | ||
•interstate transportation and storage; | ||
•midstream; | ||
•NGL transportation and services; | ||
•investment in Sunoco Logistics; | ||
•retail marketing; and | ||
•all other. | ||
Preparation of Interim Financial Statements | ||
The accompanying consolidated balance sheet as of December 31, 2013, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership as of June 30, 2014 and for the three and six months ended June 30, 2014 and 2013 have been prepared in accordance with GAAP for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting. | ||
In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of June 30, 2014, and the Partnership’s results of operations and cash flows for the three and six months ended June 30, 2014 and 2013. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the SEC on February 27, 2014. | ||
Certain prior period amounts have been reclassified to conform to the 2014 presentation. These reclassifications had no impact on net income or total equity. | ||
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 cost of products sold in the consolidated statements of operations, with no net impact on net income. Excise taxes collected by our retail marketing segment were $573 million and $563 million for the three months ended June 30, 2014 and 2013, respectively, and $1.10 billion and $1.08 billion for the six months ended June 30, 2014 and 2013, respectively. | ||
New Accounting Pronouncements | ||
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. 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. |
Acquisitions_Divestitures_and_
Acquisitions, Divestitures and Related Transactions | 6 Months Ended |
Jun. 30, 2014 | |
Acquisitions and Dispositions [Abstract] | ' |
Acquisitions And Divestitures | ' |
ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: | |
2014 | |
Susser Holdings Merger | |
On April 27, 2014, ETP entered into a definitive merger agreement whereby ETP plans to acquire Susser Holdings Corporation (“Susser Holdings”) in a unit and cash transaction for total consideration valued at approximately $1.8 billion (the “Susser Merger”). By acquiring Susser Holdings, ETP will own the general partner interest and the incentive distribution rights in Susser Petroleum Partners LP (“Susser Petroleum”), approximately 11 million Susser Petroleum common units (representing approximately 50.2% of Susser Petroleum’s outstanding units), and Susser Holdings’ existing retail operations, consisting of 630 convenience store locations. The Susser Merger is expected to close in the third quarter of 2014, subject to approval of the shareholders of Susser Holdings. | |
Trunkline LNG Transaction | |
On February 19, 2014, ETP completed the transfer to ETE of Trunkline 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 “Trunkline LNG Transaction”). This transaction was effective as of January 1, 2014, at which time ETP deconsolidated Trunkline LNG, including goodwill of $184 million and intangible assets of $50 million related to Trunkline LNG. The results of Trunkline LNG’s operations have not been presented as discontinued operations and Trunkline 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 Trunkline LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Trunkline LNG’s regasification facility and the development of a liquefaction project at Trunkline 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 10. | |
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. | |
2013 | |
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”). The general partner and IDRs of Regency are 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 have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Partnership has not presented SUGS as discontinued operations due to the Partnership’s continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency common and Class F units received, which has been accounted for using the equity method. | |
Discontinued Operations | |
Discontinued operations for the six months ended June 30, 2014 included the results of operations for a marketing business that had been recently acquired and was sold effective April 1, 2014, as well as a $39 million gain on the sale. The disposed subsidiary’s results of operations were not material during any periods in 2013; therefore, the disposed subsidiary’s results were not reclassified to discontinued operations in the prior period. | |
Discontinued operations for the three and six months ended June 30, 2013 included the results of Southern Union’s distribution operations. |
Cash_And_Cash_Equivalents
Cash And Cash Equivalents | 6 Months Ended | |||||||
Jun. 30, 2014 | ||||||||
Cash and Cash Equivalents [Abstract] | ' | |||||||
Cash And Cash Equivalents | ' | |||||||
CASH AND CASH EQUIVALENTS: | ||||||||
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. | ||||||||
The net change in operating assets and liabilities (net of acquisitions) included in cash flows from operating activities is comprised as follows: | ||||||||
Six Months Ended | ||||||||
June 30, | ||||||||
2014 | 2013 | |||||||
Accounts receivable | $ | (778 | ) | $ | (206 | ) | ||
Accounts receivable from related companies | (90 | ) | (63 | ) | ||||
Inventories | 310 | (64 | ) | |||||
Exchanges receivable | (31 | ) | (5 | ) | ||||
Other current assets | 193 | 72 | ||||||
Other non-current assets, net | (25 | ) | (32 | ) | ||||
Accounts payable | 563 | 177 | ||||||
Accounts payable to related companies | 47 | (65 | ) | |||||
Exchanges payable | (12 | ) | (2 | ) | ||||
Accrued and other current liabilities | 147 | 48 | ||||||
Other non-current liabilities | (44 | ) | (34 | ) | ||||
Price risk management assets and liabilities, net | 71 | (103 | ) | |||||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | 351 | $ | (277 | ) | |||
Non-cash investing and financing activities are as follows: | ||||||||
Six Months Ended | ||||||||
June 30, | ||||||||
2014 | 2013 | |||||||
NON-CASH INVESTING ACTIVITIES: | ||||||||
Accrued capital expenditures | $ | 291 | $ | 405 | ||||
Regency common units and Class F units received in exchange for contribution of SUGS | $ | — | $ | 961 | ||||
Net gains from subsidiary common unit issuances | $ | 14 | $ | — | ||||
NON-CASH FINANCING ACTIVITIES: | ||||||||
Issuance of Common Units in connection with the Holdco Acquisition | $ | — | $ | 2,464 | ||||
Redemption of Common Units in connection with the Trunkline LNG Transaction (see Note 2) | $ | 1,167 | $ | — | ||||
Inventories
Inventories | 6 Months Ended | |||||||
Jun. 30, 2014 | ||||||||
Inventory, Gross [Abstract] | ' | |||||||
Inventories | ' | |||||||
INVENTORIES: | ||||||||
Inventories consisted of the following: | ||||||||
June 30, 2014 | December 31, 2013 | |||||||
Natural gas and NGLs | $ | 258 | $ | 519 | ||||
Crude oil | 478 | 488 | ||||||
Refined products | 583 | 597 | ||||||
Appliances, parts and fittings and other | 177 | 161 | ||||||
Total inventories | $ | 1,496 | $ | 1,765 | ||||
We utilize commodity derivatives to manage price volatility associated with certain of our natural gas inventory and designate certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations. |
Advances_to_and_Investments_in
Advances to and Investments in Unconsolidated Affiliates (Notes) | 6 Months Ended | |
Jun. 30, 2014 | ||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES [Abstract] | ' | |
Investments in and Advances to Affiliates, Schedule of Investments [Text Block] | ' | |
5 | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: | |
AmeriGas Partners, L.P. | ||
In January 2014, June 2014 and August 2014, we sold 9.2 million, 8.5 million and 1.2 million AmeriGas common units, respectively, for net proceeds of $381 million, $377 million and $55 million, respectively. Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and for general partnership purposes. Subsequent to the August 2014 sale, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company. | ||
Bayview Refining Company, LLC | ||
In May 2014, Sunoco Logistics entered into a joint agreement to form Bayview Refining Company, LLC (“Bayview”). Bayview will construct and operate a facility that will process crude oil into intermediate petroleum products. Sunoco Logistics will fund construction of the facility through contributions proportionate to its 49% economic and voting interests, with the remaining portion funded by the joint owner through a promissory note entered into with Sunoco Logistics. Through June 30, 2014, the joint owners have made contributions totaling $8 million. The facility is expected to commence operations in the second half of 2015. Bayview is a variable interest entity of which Sunoco Logistics is not the primary beneficiary. As a result, Sunoco Logistics’ interest in Bayview is reflected as an equity method investment. |
Fair_Value_Measurements
Fair Value Measurements | 6 Months Ended | |||||||||||
Jun. 30, 2014 | ||||||||||||
Fair Value Measurements [Abstract] | ' | |||||||||||
Fair Value Measurements | ' | |||||||||||
FAIR VALUE MEASUREMENTS: | ||||||||||||
We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the six months ended June 30, 2014, no transfers were made between any levels within the fair value hierarchy. | ||||||||||||
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations at June 30, 2014 and December 31, 2013 was $19.12 billion and $17.69 billion, respectively. As of June 30, 2014 and December 31, 2013, the aggregate carrying amount of our consolidated debt obligations was $17.57 billion and $17.09 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. | ||||||||||||
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 June 30, 2014 and December 31, 2013 based on inputs used to derive their fair values: | ||||||||||||
Fair Value Measurements at | ||||||||||||
30-Jun-14 | ||||||||||||
Fair Value Total | Level 1 | Level 2 | ||||||||||
Assets: | ||||||||||||
Interest rate derivatives | $ | 3 | $ | — | $ | 3 | ||||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | 7 | 7 | — | |||||||||
Swing Swaps IFERC | 2 | 2 | — | |||||||||
Fixed Swaps/Futures | 35 | 35 | — | |||||||||
Power: | ||||||||||||
Forwards | 8 | — | 8 | |||||||||
Futures | 4 | 4 | — | |||||||||
Natural Gas Liquids – Forwards/Swaps | 7 | 7 | — | |||||||||
Refined Products – Futures | 5 | 5 | — | |||||||||
Total commodity derivatives | 68 | 60 | 8 | |||||||||
Total assets | $ | 71 | $ | 60 | $ | 11 | ||||||
Liabilities: | ||||||||||||
Interest rate derivatives | $ | (121 | ) | $ | — | $ | (121 | ) | ||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | (7 | ) | (7 | ) | — | |||||||
Swing Swaps IFERC | (2 | ) | (2 | ) | — | |||||||
Fixed Swaps/Futures | (42 | ) | (42 | ) | — | |||||||
Power: | ||||||||||||
Forwards | (6 | ) | — | (6 | ) | |||||||
Futures | (4 | ) | (4 | ) | — | |||||||
Natural Gas Liquids – Forwards/Swaps | (14 | ) | (14 | ) | — | |||||||
Refined Products – Futures | (7 | ) | (7 | ) | — | |||||||
Total commodity derivatives | (82 | ) | (76 | ) | (6 | ) | ||||||
Total liabilities | $ | (203 | ) | $ | (76 | ) | $ | (127 | ) | |||
Fair Value Measurements at | ||||||||||||
31-Dec-13 | ||||||||||||
Fair Value Total | Level 1 | Level 2 | ||||||||||
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 | 201 | 201 | — | |||||||||
Power – Forwards | 3 | — | 3 | |||||||||
Natural Gas Liquids – Forwards/Swaps | 5 | 5 | — | |||||||||
Refined Products – Futures | 5 | 5 | — | |||||||||
Total commodity derivatives | 227 | 217 | 10 | |||||||||
Total assets | $ | 274 | $ | 217 | $ | 57 | ||||||
Liabilities: | ||||||||||||
Interest rate derivatives | $ | (95 | ) | $ | — | $ | (95 | ) | ||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | (4 | ) | (4 | ) | — | |||||||
Swing Swaps IFERC | (6 | ) | — | (6 | ) | |||||||
Fixed Swaps/Futures | (201 | ) | (201 | ) | — | |||||||
Forward Physical Swaps | (1 | ) | — | (1 | ) | |||||||
Power – Forwards | (1 | ) | — | (1 | ) | |||||||
Natural Gas Liquids – Forwards/Swaps | (5 | ) | (5 | ) | — | |||||||
Refined Products – Futures | (5 | ) | (5 | ) | — | |||||||
Total commodity derivatives | (223 | ) | (215 | ) | (8 | ) | ||||||
Total liabilities | $ | (318 | ) | $ | (215 | ) | $ | (103 | ) |
Net_Income_Per_Limited_Partner
Net Income Per Limited Partner Unit | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||||||
Earnings Per Share [Text Block] | ' | |||||||||||||||
NET INCOME PER LIMITED PARTNER UNIT: | ||||||||||||||||
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. | ||||||||||||||||
A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Income from continuing operations | $ | 539 | $ | 404 | $ | 1,006 | $ | 806 | ||||||||
Less: Income from continuing operations attributable to noncontrolling interest | 110 | 89 | 186 | 178 | ||||||||||||
Income from continuing operations, net of noncontrolling interest | 429 | 315 | 820 | 628 | ||||||||||||
General Partner’s interest in income from continuing operations | 125 | 154 | 238 | 282 | ||||||||||||
Class H Unitholder’s interest in income from continuing operations | 51 | — | 100 | — | ||||||||||||
Common Unitholders’ interest in income from continuing operations | 253 | 161 | 482 | 346 | ||||||||||||
Additional earnings allocated from (to) General Partner | 1 | 23 | (2 | ) | — | |||||||||||
Distributions on employee unit awards, net of allocation to General Partner | (3 | ) | (2 | ) | (6 | ) | (5 | ) | ||||||||
Income from continuing operations available to Common Unitholders | $ | 251 | $ | 182 | $ | 474 | $ | 341 | ||||||||
Weighted average Common Units – basic | 318.5 | 352.6 | 321.4 | 326.9 | ||||||||||||
Basic income from continuing operations per Common Unit | $ | 0.79 | $ | 0.52 | $ | 1.47 | $ | 1.04 | ||||||||
Dilutive effect of unvested Unit Awards | 1 | 1.2 | 1 | 1.2 | ||||||||||||
Weighted average Common Units, assuming dilutive effect of unvested Unit Awards | 319.5 | 353.8 | 322.4 | 328.1 | ||||||||||||
Diluted income from continuing operations per Common Unit | $ | 0.79 | $ | 0.52 | $ | 1.47 | $ | 1.04 | ||||||||
Basic income from discontinued operations per Common Unit | $ | 0.13 | $ | 0.01 | $ | 0.2 | $ | 0.04 | ||||||||
Diluted income from discontinued operations per Common Unit | $ | 0.13 | $ | 0.01 | $ | 0.2 | $ | 0.04 | ||||||||
Debt_Obligations
Debt Obligations | 6 Months Ended |
Jun. 30, 2014 | |
Debt Disclosure [Abstract] | ' |
Debt Obligations | ' |
DEBT OBLIGATIONS: | |
Senior Notes | |
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. The net proceeds from the offering were used to pay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes. | |
Credit Facilities | |
ETP Credit Facility | |
The ETP Credit Facility allows for borrowings of up to $2.5 billion and expires in October 2017. 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. As of June 30, 2014, the ETP Credit Facility had no outstanding borrowings. | |
Sunoco Logistics Credit Facilities | |
Sunoco Logistics maintains a $1.5 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 increased to $2.25 billion under certain conditions. As of June 30, 2014, the Sunoco Logistics Credit Facility had $250 million outstanding. | |
Compliance with Our Covenants | |
We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of June 30, 2014. |
Redeemable_Noncontrolling_Inte
Redeemable Noncontrolling Interests (Notes) | 6 Months Ended | |
Jun. 30, 2014 | ||
Redeemable Noncontrolling Interests [Abstract] | ' | |
Redeemable Noncontrolling Interest [Table Text Block] | ' | |
9 | 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 June 30, 2014. |
Equity
Equity | 6 Months Ended | ||||||||
Jun. 30, 2014 | |||||||||
Partners' Capital Notes [Abstract] | ' | ||||||||
Equity | ' | ||||||||
EQUITY: | |||||||||
Common Units | |||||||||
The change in Common Units during the six months ended June 30, 2014 was as follows: | |||||||||
Number of Units | |||||||||
Number of Common Units at December 31, 2013 | 333.8 | ||||||||
Common Units issued in connection with Equity Distribution Agreements | 7.6 | ||||||||
Common Units issued in connection with the Distribution Reinvestment Plan | 1.3 | ||||||||
Common Units redeemed in connection with the Trunkline LNG Transaction | (18.7 | ) | |||||||
Number of Common Units at June 30, 2014 | 324 | ||||||||
During the six months ended June 30, 2014, we received proceeds of $417 million, net of commissions of $4 million, from the issuance of units pursuant to equity distribution agreements, which were used for general partnership purposes. As of June 30, 2014, approximately $725 million of our Common Units remained available to be issued under our currently effective equity distribution agreement, which was entered into in May 2014. | |||||||||
During the six months ended June 30, 2014, distributions of $67 million were reinvested under the Distribution Reinvestment Plan resulting in the issuance of 1.3 million Common Units. As of June 30, 2014, a total of 0.8 million Common Units remain available to be issued under the existing registration statement. | |||||||||
As discussed in Note 2, ETP redeemed and cancelled 18.7 million of its Common Units in connection with the Trunkline LNG Transaction. | |||||||||
Sales of Common Units by Subsidiaries | |||||||||
We account for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by Sunoco Logistics (excluding transactions with us) as capital transactions. | |||||||||
As a result of Sunoco Logistics’ issuances of common units during the six months ended June 30, 2014, we recognized increases in partners’ capital of $14 million. | |||||||||
Sales of Common Units by Sunoco Logistics | |||||||||
In May 2014, Sunoco Logistics entered into an equity distribution agreement pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $250 million. During the six months ended June 30, 2014, Sunoco Logistics received proceeds of $102 million, net of commissions of $1 million, from the issuance of units pursuant to the equity distribution agreement, which were used for general partnership purposes. As of June 30, 2014, approximately $147 million of Sunoco Logistics’ common units remained available to be issued under this agreement. | |||||||||
Quarterly Distributions of Available Cash | |||||||||
Following are distributions declared and/or paid by ETP subsequent to December 31, 2013: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
December 31, 2013 | February 7, 2014 | February 14, 2014 | $ | 0.92 | |||||
March 31, 2014 | 5-May-14 | 15-May-14 | 0.935 | ||||||
June 30, 2014 | 4-Aug-14 | 14-Aug-14 | 0.955 | ||||||
In connection with previous transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods, and ETP has agreed to make incremental distributions on the Class H Units in future periods. The net impact of these adjustments resulted in a reduction of $53 million in the distributions to be paid from ETP to ETE for the six months ended June 30, 2014. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods: | |||||||||
Total Year | |||||||||
2014 (remainder) | $ | 53 | |||||||
2015 | 51 | ||||||||
2016 | 72 | ||||||||
2017 | 50 | ||||||||
2018 | 45 | ||||||||
2019 | 35 | ||||||||
In addition to the amounts reflected above, ETE has agreed, upon closing of the Susser Merger, to amend the ETP partnership agreement to provide for, among other things, the relinquishment of $350 million in the aggregate of incentive distributions that would potentially be made to ETE over the first forty fiscal quarters commencing immediately after the consummation of the merger. Such relinquishments would cease upon the agreement of an exchange of the Susser Petroleum general partner interest and the incentive distribution rights between ETE and ETP. | |||||||||
Sunoco Logistics Quarterly Distributions of Available Cash | |||||||||
Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2013: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
December 31, 2013 | February 10, 2014 | February 14, 2014 | $ | 0.3313 | |||||
March 31, 2014 | 9-May-14 | 15-May-14 | 0.3475 | ||||||
June 30, 2014 | 8-Aug-14 | 14-Aug-14 | 0.365 | ||||||
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. | |||||||||
Accumulated Other Comprehensive Income (Loss) | |||||||||
The following table presents the components of AOCI, net of tax: | |||||||||
June 30, 2014 | December 31, 2013 | ||||||||
Available-for-sale securities | $ | 2 | $ | 2 | |||||
Foreign currency translation adjustment | (3 | ) | (1 | ) | |||||
Net loss on commodity related hedges | (4 | ) | (4 | ) | |||||
Actuarial gain related to pensions and other postretirement benefits | 55 | 56 | |||||||
Investments in unconsolidated affiliates, net | 2 | 8 | |||||||
Total AOCI, net of tax | $ | 52 | $ | 61 | |||||
Income_Taxes_Notes
Income Taxes (Notes) | 6 Months Ended |
Jun. 30, 2014 | |
Income Tax Disclosure [Abstract] | ' |
Income Tax Disclosure [Text Block] | ' |
INCOME TAXES: | |
Income tax expense from continuing operations for the six months ended June 30, 2014 included the impact of the Trunkline LNG Transaction, which was treated as a sale for tax purposes, resulting in $87 million of incremental income tax expense. |
Retirement_Benefits_Notes
Retirement Benefits (Notes) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Retirement Benefits [Abstract] | ' | |||||||||||||||
Pension and Other Postretirement Benefits Disclosure [Text Block] | ' | |||||||||||||||
RETIREMENT BENEFITS: | ||||||||||||||||
The following tables set forth the components of net period benefit cost of the Partnership’s pension and other postretirement benefit plans: | ||||||||||||||||
Three Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||
Net periodic benefit cost: | ||||||||||||||||
Service cost | $ | 1 | $ | — | $ | 3 | $ | 1 | ||||||||
Interest cost | 7 | 2 | 9 | 1 | ||||||||||||
Expected return on plan assets | (9 | ) | (2 | ) | (15 | ) | (1 | ) | ||||||||
Settlement credits | (1 | ) | — | — | — | |||||||||||
(2 | ) | — | (3 | ) | 1 | |||||||||||
Regulatory adjustment | — | — | 2 | — | ||||||||||||
Net periodic benefit cost | $ | (2 | ) | $ | — | $ | (1 | ) | $ | 1 | ||||||
Six Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||
Net periodic benefit cost: | ||||||||||||||||
Service cost | $ | 1 | $ | — | $ | 5 | $ | 1 | ||||||||
Interest cost | 15 | 3 | 18 | 3 | ||||||||||||
Expected return on plan assets | (20 | ) | (4 | ) | (30 | ) | (4 | ) | ||||||||
Actuarial loss amortization | (1 | ) | — | 1 | — | |||||||||||
Settlement credits | (2 | ) | — | (2 | ) | — | ||||||||||
(7 | ) | (1 | ) | (8 | ) | — | ||||||||||
Regulatory adjustment | — | — | 4 | — | ||||||||||||
Net periodic benefit cost | $ | (7 | ) | $ | (1 | ) | $ | (4 | ) | $ | — | |||||
Panhandle has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers. 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 reflected in expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission. | ||||||||||||||||
Panhandle no longer has pension plans after the sale of the assets of Missouri Gas Energy and New England Gas Company in 2013. |
Regulatory_Matters_Commitments
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | ' | |||||||||||||||
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | ' | |||||||||||||||
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: | ||||||||||||||||
Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus | ||||||||||||||||
Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011. | ||||||||||||||||
On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011. | ||||||||||||||||
FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs. | ||||||||||||||||
Contingent Residual Support Agreement – AmeriGas | ||||||||||||||||
In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party 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. | ||||||||||||||||
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. | ||||||||||||||||
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 2056. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Rental expense(1) | $ | 25 | $ | 30 | $ | 56 | $ | 62 | ||||||||
Less: Sublease rental income | (10 | ) | (5 | ) | (18 | ) | (10 | ) | ||||||||
Rental expense, net | $ | 15 | $ | 25 | $ | 38 | $ | 52 | ||||||||
(1) | Includes contingent rentals totaling $6 million for the three months ended June 30, 2014 and 2013, and $9 million and $10 million for the six months ended June 30, 2014 and 2013, respectively. | |||||||||||||||
Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. | ||||||||||||||||
Litigation and Contingencies | ||||||||||||||||
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. | ||||||||||||||||
MTBE Litigation | ||||||||||||||||
Sunoco, 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 June 30, 2014, Sunoco is a defendant in nine 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. Six of these cases are venued in a multidistrict litigation (“MDL”) proceeding in a New York federal court. The most recently filed Puerto Rico action is expected to be transferred to the MDL. 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 fewer than 20 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 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. | ||||||||||||||||
Other Litigation and Contingencies | ||||||||||||||||
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of June 30, 2014 and December 31, 2013, accruals of approximately $43 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 June 30, 2014 or December 31, 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. | ||||||||||||||||
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 retail sites. | |||||||||||||||
• | Legacy sites related to Sunoco, that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites. | |||||||||||||||
• | Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of June 30, 2014, Sunoco had been named as a PRP at approximately 40 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. | |||||||||||||||
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets. | ||||||||||||||||
The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. | ||||||||||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||
Current | $ | 71 | $ | 45 | ||||||||||||
Non-current | 319 | 350 | ||||||||||||||
Total environmental liabilities | $ | 390 | $ | 395 | ||||||||||||
In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. | ||||||||||||||||
During the three months ended June 30, 2014 and 2013, Sunoco recorded $9 million and $8 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2014 and 2013, Sunoco recorded $17 million and $15 million, respectively, of expenditures related to environmental cleanup programs. | ||||||||||||||||
On June 29, 2011, the U.S. Environmental Protection Agency finalized a rule under the Clean Air Act that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future. | ||||||||||||||||
Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures. | ||||||||||||||||
Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances. |
Price_Risk_Management_Assets_A
Price Risk Management Assets And Liabilities | 6 Months Ended | ||||||||||||||||||
Jun. 30, 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 NGL 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. | |||||||||||||||||||
Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, we also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy. | |||||||||||||||||||
The following table details our outstanding commodity-related derivatives: | |||||||||||||||||||
June 30, 2014 | December 31, 2013 | ||||||||||||||||||
Notional Volume | Maturity | Notional Volume | Maturity | ||||||||||||||||
Mark-to-Market Derivatives | |||||||||||||||||||
(Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Fixed Swaps/Futures | — | — | 9,457,500 | 2014-2019 | |||||||||||||||
Basis Swaps IFERC/NYMEX(1) | 16,632,500 | 2014-2015 | (487,500 | ) | 2014-2017 | ||||||||||||||
Swing Swaps | — | — | 1,937,500 | 2014-2016 | |||||||||||||||
Power (Megawatt): | |||||||||||||||||||
Forwards | 270,150 | 2014 | 351,050 | 2014 | |||||||||||||||
Futures | 10,670 | 2014 | (772,476 | ) | 2014 | ||||||||||||||
Options – Puts | (54,400 | ) | 2014 | (52,800 | ) | 2014 | |||||||||||||
Options – Calls | 54,400 | 2014 | 103,200 | 2014 | |||||||||||||||
Crude (Bbls) – Futures | (40,000 | ) | 2014 | 103,000 | 2014 | ||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | (2,537,500 | ) | 2014-2015 | 570,000 | 2014 | ||||||||||||||
Swing Swaps IFERC | 26,147,500 | 2014-2015 | (9,690,000 | ) | 2014-2016 | ||||||||||||||
Fixed Swaps/Futures | (4,445,000 | ) | 2014-2019 | (8,195,000 | ) | 2014-2015 | |||||||||||||
Forward Physical Contracts | (5,908,374 | ) | 2014-2015 | 5,668,559 | 2014-2015 | ||||||||||||||
Natural Gas Liquid (Bbls) – Forwards/Swaps | (1,823,200 | ) | 2014-2015 | (1,133,600 | ) | 2014 | |||||||||||||
Refined Products (Bbls) – Futures | (1,605,000 | ) | 2014-2015 | (280,000 | ) | 2014 | |||||||||||||
Fair Value Hedging Derivatives | |||||||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | — | — | (7,352,500 | ) | 2014 | ||||||||||||||
Fixed Swaps/Futures | (1,757,500 | ) | 2014 | (50,530,000 | ) | 2014 | |||||||||||||
Hedged Item – Inventory | 1,757,500 | 2014 | 50,530,000 | 2014 | |||||||||||||||
Cash Flow Hedging Derivatives | |||||||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | (920,000 | ) | 2014 | (1,825,000 | ) | 2014 | |||||||||||||
Fixed Swaps/Futures | (6,440,000 | ) | 2014 | (12,775,000 | ) | 2014 | |||||||||||||
Natural Gas Liquid (Bbls) – Forwards/Swaps | (510,000 | ) | 2014 | (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. | ||||||||||||||||||
We expect losses of $3 million related to commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs. | |||||||||||||||||||
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 | ||||||||||||||||
June 30, 2014 | December 31, 2013 | ||||||||||||||||||
ETP | July 2014(2) | Forward-starting to pay a fixed rate of 4.15% and receive a floating rate | $ | 300 | $ | 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 4.18% and receive a floating rate | 200 | — | |||||||||||||||
ETP | July 2018(4) | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | 200 | — | |||||||||||||||
ETP | Jul-18 | Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% | — | 600 | |||||||||||||||
ETP | Jun-21 | Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% | — | 400 | |||||||||||||||
ETP | Feb-23 | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | 200 | 400 | |||||||||||||||
Panhandle | Nov-21 | Pay a fixed rate of 3.80% and receive a floating rate | 275 | 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, utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that could 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 | ||||||||||||||||||
June 30, 2014 | December 31, 2013 | June 30, 2014 | December 31, 2013 | ||||||||||||||||
Derivatives designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives (margin deposits) | $ | 1 | $ | 3 | $ | (4 | ) | $ | (18 | ) | |||||||||
1 | 3 | (4 | ) | (18 | ) | ||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives (margin deposits) | 59 | 227 | (73 | ) | (209 | ) | |||||||||||||
Commodity derivatives | 47 | 39 | (44 | ) | (38 | ) | |||||||||||||
Interest rate derivatives | 3 | 47 | (121 | ) | (95 | ) | |||||||||||||
109 | 313 | (238 | ) | (342 | ) | ||||||||||||||
Total derivatives | $ | 110 | $ | 316 | $ | (242 | ) | $ | (360 | ) | |||||||||
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 | June 30, 2014 | December 31, 2013 | June 30, 2014 | December 31, 2013 | |||||||||||||||
Derivatives in offsetting agreements: | |||||||||||||||||||
OTC contracts | Price risk management assets (liabilities) | $ | 47 | $ | 41 | $ | (44 | ) | $ | (38 | ) | ||||||||
Broker cleared derivative contracts | Other current assets | 106 | 265 | (150 | ) | (318 | ) | ||||||||||||
153 | 306 | (194 | ) | (356 | ) | ||||||||||||||
Offsetting agreements: | |||||||||||||||||||
Counterparty netting | Price risk management assets (liabilities) | (38 | ) | (36 | ) | 38 | 36 | ||||||||||||
Payments on margin deposit | Other current assets | (8 | ) | (1 | ) | 35 | 55 | ||||||||||||
(46 | ) | (37 | ) | 73 | 91 | ||||||||||||||
Net derivatives with offsetting agreements | 107 | 269 | (121 | ) | (265 | ) | |||||||||||||
Derivatives without offsetting agreements | 3 | 47 | (121 | ) | (95 | ) | |||||||||||||
Total derivatives | $ | 110 | $ | 316 | $ | (242 | ) | $ | (360 | ) | |||||||||
We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date. | |||||||||||||||||||
The following tables summarize the amounts recognized with respect to our derivative financial instruments: | |||||||||||||||||||
Change in Value Recognized in OCI on Derivatives | |||||||||||||||||||
(Effective Portion) | |||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Derivatives in cash flow hedging relationships: | |||||||||||||||||||
Commodity derivatives | $ | (2 | ) | $ | 6 | $ | (6 | ) | $ | 8 | |||||||||
Total | $ | (2 | ) | $ | 6 | $ | (6 | ) | $ | 8 | |||||||||
Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Amount of Gain/(Loss) Reclassified from AOCI into Income | ||||||||||||||||||
(Effective Portion) | |||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Derivatives in cash flow hedging relationships: | |||||||||||||||||||
Commodity derivatives | Cost of products sold | $ | (2 | ) | $ | 1 | $ | (6 | ) | $ | 2 | ||||||||
Total | $ | (2 | ) | $ | 1 | $ | (6 | ) | $ | 2 | |||||||||
Location of Gain/(Loss) Recognized in Income on Derivatives | Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | ||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Derivatives in fair value hedging relationships (including hedged item): | |||||||||||||||||||
Commodity derivatives | Cost of products sold | $ | — | $ | (1 | ) | $ | (6 | ) | $ | 4 | ||||||||
Total | $ | — | $ | (1 | ) | $ | (6 | ) | $ | 4 | |||||||||
Location of Gain/(Loss) Recognized in Income on Derivatives | Amount of Gain/(Loss) Recognized in Income on Derivatives | ||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives – Trading | Cost of products sold | $ | (5 | ) | $ | 3 | $ | 2 | $ | (1 | ) | ||||||||
Commodity derivatives – Non-trading | Cost of products sold | (32 | ) | 21 | (25 | ) | 3 | ||||||||||||
Commodity derivatives – Non-trading | Deferred gas purchases | — | 2 | — | (3 | ) | |||||||||||||
Interest rate derivatives | Gains (losses) on interest rate derivatives | (46 | ) | 39 | (48 | ) | 46 | ||||||||||||
Total | $ | (83 | ) | $ | 65 | $ | (71 | ) | $ | 45 | |||||||||
Related_Party_Transactions
Related Party Transactions | 6 Months Ended | |||||||||||||||
Jun. 30, 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 Trunkline LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Trunkline LNG’s regasification facility and the development of a liquefaction project at Trunkline 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: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Affiliated revenues | $ | 390 | $ | 333 | $ | 731 | $ | 715 | ||||||||
The following table summarizes the related company balances on our consolidated balance sheets: | ||||||||||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||
Accounts receivable from related companies: | ||||||||||||||||
ETE | $ | 64 | $ | 18 | ||||||||||||
Regency | 62 | 53 | ||||||||||||||
PES | 6 | 7 | ||||||||||||||
FGT | 14 | 29 | ||||||||||||||
ET Crude Oil | 24 | 24 | ||||||||||||||
Trunkline LNG | 30 | — | ||||||||||||||
Other | 55 | 34 | ||||||||||||||
Total accounts receivable from related companies: | $ | 255 | $ | 165 | ||||||||||||
Accounts payable to related companies: | ||||||||||||||||
ETE | $ | 3 | $ | 8 | ||||||||||||
Regency | 55 | 24 | ||||||||||||||
PES | 16 | — | ||||||||||||||
FGT | 2 | 8 | ||||||||||||||
Trunkline LNG | 10 | — | ||||||||||||||
Other | 2 | 5 | ||||||||||||||
Total accounts payable to related companies: | $ | 88 | $ | 45 | ||||||||||||
Other_Information
Other Information | 6 Months Ended | |||||||
Jun. 30, 2014 | ||||||||
Other Information [Abstract] | ' | |||||||
Other Information | ' | |||||||
OTHER INFORMATION: | ||||||||
The following tables present additional detail for certain balance sheet captions. | ||||||||
Other Current Assets | ||||||||
Other current assets consisted of the following: | ||||||||
June 30, 2014 | December 31, 2013 | |||||||
Deposits paid to vendors | $ | 40 | $ | 49 | ||||
Prepaid and other | 226 | 261 | ||||||
Total other current assets | $ | 266 | $ | 310 | ||||
Accrued and Other Current Liabilities | ||||||||
Accrued and other current liabilities consisted of the following: | ||||||||
June 30, 2014 | December 31, 2013 | |||||||
Interest payable | $ | 296 | $ | 294 | ||||
Customer advances and deposits | 84 | 126 | ||||||
Accrued capital expenditures | 291 | 166 | ||||||
Accrued wages and benefits | 107 | 155 | ||||||
Taxes payable other than income taxes | 295 | 214 | ||||||
Income taxes payable | 219 | 3 | ||||||
Deferred income taxes | 152 | 119 | ||||||
Other | 238 | 351 | ||||||
Total accrued and other current liabilities | $ | 1,682 | $ | 1,428 | ||||
Reportable_Segments
Reportable Segments | 6 Months Ended | |||||||||||||||
Jun. 30, 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; | ||||||||||||||||
•NGL transportation and services; | ||||||||||||||||
•investment in Sunoco Logistics; | ||||||||||||||||
•retail marketing; and | ||||||||||||||||
•all other. | ||||||||||||||||
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 NGL 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. | ||||||||||||||||
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: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Revenues: | ||||||||||||||||
Intrastate transportation and storage: | ||||||||||||||||
Revenues from external customers | $ | 669 | $ | 558 | $ | 1,516 | $ | 1,203 | ||||||||
Intersegment revenues | 43 | 65 | 130 | 104 | ||||||||||||
712 | 623 | 1,646 | 1,307 | |||||||||||||
Interstate transportation and storage: | ||||||||||||||||
Revenues from external customers | 245 | 354 | 540 | 677 | ||||||||||||
Intersegment revenues | 4 | 3 | 7 | 4 | ||||||||||||
249 | 357 | 547 | 681 | |||||||||||||
Midstream: | ||||||||||||||||
Revenues from external customers | 302 | 308 | 604 | 639 | ||||||||||||
Intersegment revenues | 418 | 269 | 769 | 538 | ||||||||||||
720 | 577 | 1,373 | 1,177 | |||||||||||||
NGL transportation and services: | ||||||||||||||||
Revenues from external customers | 878 | 420 | 1,679 | 766 | ||||||||||||
Intersegment revenues | 25 | 18 | 54 | 37 | ||||||||||||
903 | 438 | 1,733 | 803 | |||||||||||||
Investment in Sunoco Logistics: | ||||||||||||||||
Revenues from external customers | 4,766 | 4,256 | 9,218 | 7,713 | ||||||||||||
Intersegment revenues | 55 | 55 | 80 | 110 | ||||||||||||
4,821 | 4,311 | 9,298 | 7,823 | |||||||||||||
Retail marketing: | ||||||||||||||||
Revenues from external customers | 5,568 | 5,291 | 10,576 | 10,508 | ||||||||||||
Intersegment revenues | — | — | 3 | 5 | ||||||||||||
5,568 | 5,291 | 10,579 | 10,513 | |||||||||||||
All other: | ||||||||||||||||
Revenues from external customers | 601 | 364 | 1,128 | 899 | ||||||||||||
Intersegment revenues | 120 | 121 | 184 | 217 | ||||||||||||
721 | 485 | 1,312 | 1,116 | |||||||||||||
Eliminations | (665 | ) | (531 | ) | (1,227 | ) | (1,015 | ) | ||||||||
Total revenues | $ | 13,029 | $ | 11,551 | $ | 25,261 | $ | 22,405 | ||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Segment Adjusted EBITDA: | ||||||||||||||||
Intrastate transportation and storage | $ | 110 | $ | 112 | $ | 287 | $ | 244 | ||||||||
Interstate transportation and storage | 265 | 361 | 565 | 658 | ||||||||||||
Midstream | 157 | 127 | 283 | 214 | ||||||||||||
NGL transportation and services | 141 | 77 | 269 | 157 | ||||||||||||
Investment in Sunoco Logistics | 280 | 244 | 488 | 480 | ||||||||||||
Retail marketing | 136 | 97 | 245 | 134 | ||||||||||||
All other | 80 | 51 | 238 | 138 | ||||||||||||
Total | 1,169 | 1,069 | 2,375 | 2,025 | ||||||||||||
Depreciation and amortization | (268 | ) | (251 | ) | (534 | ) | (511 | ) | ||||||||
Interest expense, net of interest capitalized | (217 | ) | (211 | ) | (436 | ) | (422 | ) | ||||||||
Gain on sale of AmeriGas common units | 93 | — | 163 | — | ||||||||||||
Gains (losses) on interest rate derivatives | (46 | ) | 39 | (48 | ) | 46 | ||||||||||
Non-cash unit-based compensation expense | (13 | ) | (10 | ) | (27 | ) | (24 | ) | ||||||||
Unrealized gains (losses) on commodity risk management activities | (1 | ) | 18 | (30 | ) | 37 | ||||||||||
LIFO valuation adjustments | 20 | (22 | ) | 34 | 16 | |||||||||||
Adjusted EBITDA related to discontinued operations | — | (23 | ) | (27 | ) | (63 | ) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | (170 | ) | (158 | ) | (366 | ) | (323 | ) | ||||||||
Equity in earnings of unconsolidated affiliates | 57 | 37 | 136 | 109 | ||||||||||||
Other, net | (15 | ) | 5 | (18 | ) | 8 | ||||||||||
Income from continuing operations before income tax expense | $ | 609 | $ | 493 | $ | 1,222 | $ | 898 | ||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||
Total assets: | ||||||||||||||||
Intrastate transportation and storage | $ | 4,504 | $ | 4,606 | ||||||||||||
Interstate transportation and storage | 10,158 | 10,988 | ||||||||||||||
Midstream | 3,307 | 3,133 | ||||||||||||||
NGL transportation and services | 4,576 | 4,326 | ||||||||||||||
Investment in Sunoco Logistics | 13,437 | 11,650 | ||||||||||||||
Retail marketing | 4,532 | 3,936 | ||||||||||||||
All other | 3,709 | 5,063 | ||||||||||||||
Total | $ | 44,223 | $ | 43,702 | ||||||||||||
Operations_And_Organization_Ac
Operations And Organization Accounting Policy (Policies) | 6 Months Ended |
Jun. 30, 2014 | |
Accounting Policies [Abstract] | ' |
New Accounting Pronouncements, Policy [Policy Text Block] | ' |
New Accounting Pronouncements | |
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. 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. |
Cash_And_Cash_Equivalents_Tabl
Cash And Cash Equivalents (Tables) | 6 Months Ended | |||||||
Jun. 30, 2014 | ||||||||
Cash and Cash Equivalents [Abstract] | ' | |||||||
Net Cash Provided By Operating Activities | ' | |||||||
The net change in operating assets and liabilities (net of acquisitions) included in cash flows from operating activities is comprised as follows: | ||||||||
Six Months Ended | ||||||||
June 30, | ||||||||
2014 | 2013 | |||||||
Accounts receivable | $ | (778 | ) | $ | (206 | ) | ||
Accounts receivable from related companies | (90 | ) | (63 | ) | ||||
Inventories | 310 | (64 | ) | |||||
Exchanges receivable | (31 | ) | (5 | ) | ||||
Other current assets | 193 | 72 | ||||||
Other non-current assets, net | (25 | ) | (32 | ) | ||||
Accounts payable | 563 | 177 | ||||||
Accounts payable to related companies | 47 | (65 | ) | |||||
Exchanges payable | (12 | ) | (2 | ) | ||||
Accrued and other current liabilities | 147 | 48 | ||||||
Other non-current liabilities | (44 | ) | (34 | ) | ||||
Price risk management assets and liabilities, net | 71 | (103 | ) | |||||
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | 351 | $ | (277 | ) | |||
Non-Cash Investing And Financing Activities | ' | |||||||
Non-cash investing and financing activities are as follows: | ||||||||
Six Months Ended | ||||||||
June 30, | ||||||||
2014 | 2013 | |||||||
NON-CASH INVESTING ACTIVITIES: | ||||||||
Accrued capital expenditures | $ | 291 | $ | 405 | ||||
Regency common units and Class F units received in exchange for contribution of SUGS | $ | — | $ | 961 | ||||
Net gains from subsidiary common unit issuances | $ | 14 | $ | — | ||||
NON-CASH FINANCING ACTIVITIES: | ||||||||
Issuance of Common Units in connection with the Holdco Acquisition | $ | — | $ | 2,464 | ||||
Redemption of Common Units in connection with the Trunkline LNG Transaction (see Note 2) | $ | 1,167 | $ | — | ||||
Inventories_Tables
Inventories (Tables) | 6 Months Ended | |||||||
Jun. 30, 2014 | ||||||||
Inventory, Gross [Abstract] | ' | |||||||
Schedule Of Inventories | ' | |||||||
Inventories consisted of the following: | ||||||||
June 30, 2014 | December 31, 2013 | |||||||
Natural gas and NGLs | $ | 258 | $ | 519 | ||||
Crude oil | 478 | 488 | ||||||
Refined products | 583 | 597 | ||||||
Appliances, parts and fittings and other | 177 | 161 | ||||||
Total inventories | $ | 1,496 | $ | 1,765 | ||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 6 Months Ended | |||||||||||
Jun. 30, 2014 | ||||||||||||
Fair Value Measurements [Abstract] | ' | |||||||||||
Fair Value Of Assets And Liabilities Measured And Recorded On Recurring Basis | ' | |||||||||||
The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2014 and December 31, 2013 based on inputs used to derive their fair values: | ||||||||||||
Fair Value Measurements at | ||||||||||||
30-Jun-14 | ||||||||||||
Fair Value Total | Level 1 | Level 2 | ||||||||||
Assets: | ||||||||||||
Interest rate derivatives | $ | 3 | $ | — | $ | 3 | ||||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | 7 | 7 | — | |||||||||
Swing Swaps IFERC | 2 | 2 | — | |||||||||
Fixed Swaps/Futures | 35 | 35 | — | |||||||||
Power: | ||||||||||||
Forwards | 8 | — | 8 | |||||||||
Futures | 4 | 4 | — | |||||||||
Natural Gas Liquids – Forwards/Swaps | 7 | 7 | — | |||||||||
Refined Products – Futures | 5 | 5 | — | |||||||||
Total commodity derivatives | 68 | 60 | 8 | |||||||||
Total assets | $ | 71 | $ | 60 | $ | 11 | ||||||
Liabilities: | ||||||||||||
Interest rate derivatives | $ | (121 | ) | $ | — | $ | (121 | ) | ||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | (7 | ) | (7 | ) | — | |||||||
Swing Swaps IFERC | (2 | ) | (2 | ) | — | |||||||
Fixed Swaps/Futures | (42 | ) | (42 | ) | — | |||||||
Power: | ||||||||||||
Forwards | (6 | ) | — | (6 | ) | |||||||
Futures | (4 | ) | (4 | ) | — | |||||||
Natural Gas Liquids – Forwards/Swaps | (14 | ) | (14 | ) | — | |||||||
Refined Products – Futures | (7 | ) | (7 | ) | — | |||||||
Total commodity derivatives | (82 | ) | (76 | ) | (6 | ) | ||||||
Total liabilities | $ | (203 | ) | $ | (76 | ) | $ | (127 | ) | |||
Fair Value Measurements at | ||||||||||||
31-Dec-13 | ||||||||||||
Fair Value Total | Level 1 | Level 2 | ||||||||||
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 | 201 | 201 | — | |||||||||
Power – Forwards | 3 | — | 3 | |||||||||
Natural Gas Liquids – Forwards/Swaps | 5 | 5 | — | |||||||||
Refined Products – Futures | 5 | 5 | — | |||||||||
Total commodity derivatives | 227 | 217 | 10 | |||||||||
Total assets | $ | 274 | $ | 217 | $ | 57 | ||||||
Liabilities: | ||||||||||||
Interest rate derivatives | $ | (95 | ) | $ | — | $ | (95 | ) | ||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | (4 | ) | (4 | ) | — | |||||||
Swing Swaps IFERC | (6 | ) | — | (6 | ) | |||||||
Fixed Swaps/Futures | (201 | ) | (201 | ) | — | |||||||
Forward Physical Swaps | (1 | ) | — | (1 | ) | |||||||
Power – Forwards | (1 | ) | — | (1 | ) | |||||||
Natural Gas Liquids – Forwards/Swaps | (5 | ) | (5 | ) | — | |||||||
Refined Products – Futures | (5 | ) | (5 | ) | — | |||||||
Total commodity derivatives | (223 | ) | (215 | ) | (8 | ) | ||||||
Total liabilities | $ | (318 | ) | $ | (215 | ) | $ | (103 | ) |
Net_Income_Per_Limited_Partner1
Net Income Per Limited Partner Unit (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | ' | |||||||||||||||
A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Income from continuing operations | $ | 539 | $ | 404 | $ | 1,006 | $ | 806 | ||||||||
Less: Income from continuing operations attributable to noncontrolling interest | 110 | 89 | 186 | 178 | ||||||||||||
Income from continuing operations, net of noncontrolling interest | 429 | 315 | 820 | 628 | ||||||||||||
General Partner’s interest in income from continuing operations | 125 | 154 | 238 | 282 | ||||||||||||
Class H Unitholder’s interest in income from continuing operations | 51 | — | 100 | — | ||||||||||||
Common Unitholders’ interest in income from continuing operations | 253 | 161 | 482 | 346 | ||||||||||||
Additional earnings allocated from (to) General Partner | 1 | 23 | (2 | ) | — | |||||||||||
Distributions on employee unit awards, net of allocation to General Partner | (3 | ) | (2 | ) | (6 | ) | (5 | ) | ||||||||
Income from continuing operations available to Common Unitholders | $ | 251 | $ | 182 | $ | 474 | $ | 341 | ||||||||
Weighted average Common Units – basic | 318.5 | 352.6 | 321.4 | 326.9 | ||||||||||||
Basic income from continuing operations per Common Unit | $ | 0.79 | $ | 0.52 | $ | 1.47 | $ | 1.04 | ||||||||
Dilutive effect of unvested Unit Awards | 1 | 1.2 | 1 | 1.2 | ||||||||||||
Weighted average Common Units, assuming dilutive effect of unvested Unit Awards | 319.5 | 353.8 | 322.4 | 328.1 | ||||||||||||
Diluted income from continuing operations per Common Unit | $ | 0.79 | $ | 0.52 | $ | 1.47 | $ | 1.04 | ||||||||
Basic income from discontinued operations per Common Unit | $ | 0.13 | $ | 0.01 | $ | 0.2 | $ | 0.04 | ||||||||
Diluted income from discontinued operations per Common Unit | $ | 0.13 | $ | 0.01 | $ | 0.2 | $ | 0.04 | ||||||||
Equity_Tables
Equity (Tables) | 6 Months Ended | ||||||||
Jun. 30, 2014 | |||||||||
Change In Common Units | ' | ||||||||
The change in Common Units during the six months ended June 30, 2014 was as follows: | |||||||||
Number of Units | |||||||||
Number of Common Units at December 31, 2013 | 333.8 | ||||||||
Common Units issued in connection with Equity Distribution Agreements | 7.6 | ||||||||
Common Units issued in connection with the Distribution Reinvestment Plan | 1.3 | ||||||||
Common Units redeemed in connection with the Trunkline LNG Transaction | (18.7 | ) | |||||||
Number of Common Units at June 30, 2014 | 324 | ||||||||
Schedule of Net IDR Subsidies [Table Text Block] | ' | ||||||||
In connection with previous transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods, and ETP has agreed to make incremental distributions on the Class H Units in future periods. The net impact of these adjustments resulted in a reduction of $53 million in the distributions to be paid from ETP to ETE for the six months ended June 30, 2014. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods: | |||||||||
Total Year | |||||||||
2014 (remainder) | $ | 53 | |||||||
2015 | 51 | ||||||||
2016 | 72 | ||||||||
2017 | 50 | ||||||||
2018 | 45 | ||||||||
2019 | 35 | ||||||||
Accumulated Other Comprehensive Income | ' | ||||||||
The following table presents the components of AOCI, net of tax: | |||||||||
June 30, 2014 | December 31, 2013 | ||||||||
Available-for-sale securities | $ | 2 | $ | 2 | |||||
Foreign currency translation adjustment | (3 | ) | (1 | ) | |||||
Net loss on commodity related hedges | (4 | ) | (4 | ) | |||||
Actuarial gain related to pensions and other postretirement benefits | 55 | 56 | |||||||
Investments in unconsolidated affiliates, net | 2 | 8 | |||||||
Total AOCI, net of tax | $ | 52 | $ | 61 | |||||
ETP [Member] | ' | ||||||||
Distributions Made to Limited Partner, by Distribution [Table Text Block] | ' | ||||||||
Following are distributions declared and/or paid by ETP subsequent to December 31, 2013: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
December 31, 2013 | February 7, 2014 | February 14, 2014 | $ | 0.92 | |||||
March 31, 2014 | 5-May-14 | 15-May-14 | 0.935 | ||||||
June 30, 2014 | 4-Aug-14 | 14-Aug-14 | 0.955 | ||||||
Investment in Sunoco Logistics: | ' | ||||||||
Distributions Made to Limited Partner, by Distribution [Table Text Block] | ' | ||||||||
Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2013: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
December 31, 2013 | February 10, 2014 | February 14, 2014 | $ | 0.3313 | |||||
March 31, 2014 | 9-May-14 | 15-May-14 | 0.3475 | ||||||
June 30, 2014 | 8-Aug-14 | 14-Aug-14 | 0.365 | ||||||
Retirement_Benefits_Tables
Retirement Benefits (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Retirement Benefits [Abstract] | ' | |||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | ' | |||||||||||||||
The following tables set forth the components of net period benefit cost of the Partnership’s pension and other postretirement benefit plans: | ||||||||||||||||
Three Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||
Net periodic benefit cost: | ||||||||||||||||
Service cost | $ | 1 | $ | — | $ | 3 | $ | 1 | ||||||||
Interest cost | 7 | 2 | 9 | 1 | ||||||||||||
Expected return on plan assets | (9 | ) | (2 | ) | (15 | ) | (1 | ) | ||||||||
Settlement credits | (1 | ) | — | — | — | |||||||||||
(2 | ) | — | (3 | ) | 1 | |||||||||||
Regulatory adjustment | — | — | 2 | — | ||||||||||||
Net periodic benefit cost | $ | (2 | ) | $ | — | $ | (1 | ) | $ | 1 | ||||||
Six Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||
Net periodic benefit cost: | ||||||||||||||||
Service cost | $ | 1 | $ | — | $ | 5 | $ | 1 | ||||||||
Interest cost | 15 | 3 | 18 | 3 | ||||||||||||
Expected return on plan assets | (20 | ) | (4 | ) | (30 | ) | (4 | ) | ||||||||
Actuarial loss amortization | (1 | ) | — | 1 | — | |||||||||||
Settlement credits | (2 | ) | — | (2 | ) | — | ||||||||||
(7 | ) | (1 | ) | (8 | ) | — | ||||||||||
Regulatory adjustment | — | — | 4 | — | ||||||||||||
Net periodic benefit cost | $ | (7 | ) | $ | (1 | ) | $ | (4 | ) | $ | — | |||||
Regulatory_Matters_Commitments1
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | |||||||||||||||
Schedule of Rent Expense [Table Text Block] | ' | |||||||||||||||
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Rental expense(1) | $ | 25 | $ | 30 | $ | 56 | $ | 62 | ||||||||
Less: Sublease rental income | (10 | ) | (5 | ) | (18 | ) | (10 | ) | ||||||||
Rental expense, net | $ | 15 | $ | 25 | $ | 38 | $ | 52 | ||||||||
(1) | Includes contingent rentals totaling $6 million for the three months ended June 30, 2014 and 2013, and $9 million and $10 million for the six months ended June 30, 2014 and 2013, respectively. | |||||||||||||||
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. | ||||||||||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||
Current | $ | 71 | $ | 45 | ||||||||||||
Non-current | 319 | 350 | ||||||||||||||
Total environmental liabilities | $ | 390 | $ | 395 | ||||||||||||
Price_Risk_Management_Assets_A1
Price Risk Management Assets And Liabilities (Tables) | 6 Months Ended | ||||||||||||||||||
Jun. 30, 2014 | |||||||||||||||||||
Derivative [Line Items] | ' | ||||||||||||||||||
Outstanding Commodity-Related Derivatives | ' | ||||||||||||||||||
The following table details our outstanding commodity-related derivatives: | |||||||||||||||||||
June 30, 2014 | December 31, 2013 | ||||||||||||||||||
Notional Volume | Maturity | Notional Volume | Maturity | ||||||||||||||||
Mark-to-Market Derivatives | |||||||||||||||||||
(Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Fixed Swaps/Futures | — | — | 9,457,500 | 2014-2019 | |||||||||||||||
Basis Swaps IFERC/NYMEX(1) | 16,632,500 | 2014-2015 | (487,500 | ) | 2014-2017 | ||||||||||||||
Swing Swaps | — | — | 1,937,500 | 2014-2016 | |||||||||||||||
Power (Megawatt): | |||||||||||||||||||
Forwards | 270,150 | 2014 | 351,050 | 2014 | |||||||||||||||
Futures | 10,670 | 2014 | (772,476 | ) | 2014 | ||||||||||||||
Options – Puts | (54,400 | ) | 2014 | (52,800 | ) | 2014 | |||||||||||||
Options – Calls | 54,400 | 2014 | 103,200 | 2014 | |||||||||||||||
Crude (Bbls) – Futures | (40,000 | ) | 2014 | 103,000 | 2014 | ||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | (2,537,500 | ) | 2014-2015 | 570,000 | 2014 | ||||||||||||||
Swing Swaps IFERC | 26,147,500 | 2014-2015 | (9,690,000 | ) | 2014-2016 | ||||||||||||||
Fixed Swaps/Futures | (4,445,000 | ) | 2014-2019 | (8,195,000 | ) | 2014-2015 | |||||||||||||
Forward Physical Contracts | (5,908,374 | ) | 2014-2015 | 5,668,559 | 2014-2015 | ||||||||||||||
Natural Gas Liquid (Bbls) – Forwards/Swaps | (1,823,200 | ) | 2014-2015 | (1,133,600 | ) | 2014 | |||||||||||||
Refined Products (Bbls) – Futures | (1,605,000 | ) | 2014-2015 | (280,000 | ) | 2014 | |||||||||||||
Fair Value Hedging Derivatives | |||||||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | — | — | (7,352,500 | ) | 2014 | ||||||||||||||
Fixed Swaps/Futures | (1,757,500 | ) | 2014 | (50,530,000 | ) | 2014 | |||||||||||||
Hedged Item – Inventory | 1,757,500 | 2014 | 50,530,000 | 2014 | |||||||||||||||
Cash Flow Hedging Derivatives | |||||||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | (920,000 | ) | 2014 | (1,825,000 | ) | 2014 | |||||||||||||
Fixed Swaps/Futures | (6,440,000 | ) | 2014 | (12,775,000 | ) | 2014 | |||||||||||||
Natural Gas Liquid (Bbls) – Forwards/Swaps | (510,000 | ) | 2014 | (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. | ||||||||||||||||||
Interest Rate Swaps Outstanding | ' | ||||||||||||||||||
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 | ||||||||||||||||
June 30, 2014 | December 31, 2013 | ||||||||||||||||||
ETP | July 2014(2) | Forward-starting to pay a fixed rate of 4.15% and receive a floating rate | $ | 300 | $ | 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 4.18% and receive a floating rate | 200 | — | |||||||||||||||
ETP | July 2018(4) | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | 200 | — | |||||||||||||||
ETP | Jul-18 | Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% | — | 600 | |||||||||||||||
ETP | Jun-21 | Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% | — | 400 | |||||||||||||||
ETP | Feb-23 | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | 200 | 400 | |||||||||||||||
Panhandle | Nov-21 | Pay a fixed rate of 3.80% and receive a floating rate | 275 | 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. | ||||||||||||||||||
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 | ||||||||||||||||||
June 30, 2014 | December 31, 2013 | June 30, 2014 | December 31, 2013 | ||||||||||||||||
Derivatives designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives (margin deposits) | $ | 1 | $ | 3 | $ | (4 | ) | $ | (18 | ) | |||||||||
1 | 3 | (4 | ) | (18 | ) | ||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives (margin deposits) | 59 | 227 | (73 | ) | (209 | ) | |||||||||||||
Commodity derivatives | 47 | 39 | (44 | ) | (38 | ) | |||||||||||||
Interest rate derivatives | 3 | 47 | (121 | ) | (95 | ) | |||||||||||||
109 | 313 | (238 | ) | (342 | ) | ||||||||||||||
Total derivatives | $ | 110 | $ | 316 | $ | (242 | ) | $ | (360 | ) | |||||||||
Derivatives, Offsetting Fair Value Amounts [Table Text Block] | ' | ||||||||||||||||||
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: | |||||||||||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||||||||||
Balance Sheet Location | June 30, 2014 | December 31, 2013 | June 30, 2014 | December 31, 2013 | |||||||||||||||
Derivatives in offsetting agreements: | |||||||||||||||||||
OTC contracts | Price risk management assets (liabilities) | $ | 47 | $ | 41 | $ | (44 | ) | $ | (38 | ) | ||||||||
Broker cleared derivative contracts | Other current assets | 106 | 265 | (150 | ) | (318 | ) | ||||||||||||
153 | 306 | (194 | ) | (356 | ) | ||||||||||||||
Offsetting agreements: | |||||||||||||||||||
Counterparty netting | Price risk management assets (liabilities) | (38 | ) | (36 | ) | 38 | 36 | ||||||||||||
Payments on margin deposit | Other current assets | (8 | ) | (1 | ) | 35 | 55 | ||||||||||||
(46 | ) | (37 | ) | 73 | 91 | ||||||||||||||
Net derivatives with offsetting agreements | 107 | 269 | (121 | ) | (265 | ) | |||||||||||||
Derivatives without offsetting agreements | 3 | 47 | (121 | ) | (95 | ) | |||||||||||||
Total derivatives | $ | 110 | $ | 316 | $ | (242 | ) | $ | (360 | ) | |||||||||
Partnership's Derivative Assets And Liabilities | ' | ||||||||||||||||||
The following tables summarize the amounts recognized with respect to our derivative financial instruments: | |||||||||||||||||||
Change in Value Recognized in OCI on Derivatives | |||||||||||||||||||
(Effective Portion) | |||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Derivatives in cash flow hedging relationships: | |||||||||||||||||||
Commodity derivatives | $ | (2 | ) | $ | 6 | $ | (6 | ) | $ | 8 | |||||||||
Total | $ | (2 | ) | $ | 6 | $ | (6 | ) | $ | 8 | |||||||||
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block] | ' | ||||||||||||||||||
Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Amount of Gain/(Loss) Reclassified from AOCI into Income | ||||||||||||||||||
(Effective Portion) | |||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Derivatives in cash flow hedging relationships: | |||||||||||||||||||
Commodity derivatives | Cost of products sold | $ | (2 | ) | $ | 1 | $ | (6 | ) | $ | 2 | ||||||||
Total | $ | (2 | ) | $ | 1 | $ | (6 | ) | $ | 2 | |||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ' | ||||||||||||||||||
Location of Gain/(Loss) Recognized in Income on Derivatives | Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | ||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Derivatives in fair value hedging relationships (including hedged item): | |||||||||||||||||||
Commodity derivatives | Cost of products sold | $ | — | $ | (1 | ) | $ | (6 | ) | $ | 4 | ||||||||
Total | $ | — | $ | (1 | ) | $ | (6 | ) | $ | 4 | |||||||||
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ' | ||||||||||||||||||
Location of Gain/(Loss) Recognized in Income on Derivatives | Amount of Gain/(Loss) Recognized in Income on Derivatives | ||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives – Trading | Cost of products sold | $ | (5 | ) | $ | 3 | $ | 2 | $ | (1 | ) | ||||||||
Commodity derivatives – Non-trading | Cost of products sold | (32 | ) | 21 | (25 | ) | 3 | ||||||||||||
Commodity derivatives – Non-trading | Deferred gas purchases | — | 2 | — | (3 | ) | |||||||||||||
Interest rate derivatives | Gains (losses) on interest rate derivatives | (46 | ) | 39 | (48 | ) | 46 | ||||||||||||
Total | $ | (83 | ) | $ | 65 | $ | (71 | ) | $ | 45 | |||||||||
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Related Party Transactions [Abstract] | ' | |||||||||||||||
Related Party Transactions For Period Presented [Table Text Block] | ' | |||||||||||||||
The following table summarizes the affiliate revenues on our consolidated statements of operations: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Affiliated revenues | $ | 390 | $ | 333 | $ | 731 | $ | 715 | ||||||||
Related Party Balances For Period Presented [Table Text Block] | ' | |||||||||||||||
The following table summarizes the related company balances on our consolidated balance sheets: | ||||||||||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||
Accounts receivable from related companies: | ||||||||||||||||
ETE | $ | 64 | $ | 18 | ||||||||||||
Regency | 62 | 53 | ||||||||||||||
PES | 6 | 7 | ||||||||||||||
FGT | 14 | 29 | ||||||||||||||
ET Crude Oil | 24 | 24 | ||||||||||||||
Trunkline LNG | 30 | — | ||||||||||||||
Other | 55 | 34 | ||||||||||||||
Total accounts receivable from related companies: | $ | 255 | $ | 165 | ||||||||||||
Accounts payable to related companies: | ||||||||||||||||
ETE | $ | 3 | $ | 8 | ||||||||||||
Regency | 55 | 24 | ||||||||||||||
PES | 16 | — | ||||||||||||||
FGT | 2 | 8 | ||||||||||||||
Trunkline LNG | 10 | — | ||||||||||||||
Other | 2 | 5 | ||||||||||||||
Total accounts payable to related companies: | $ | 88 | $ | 45 | ||||||||||||
Other_Information_Tables
Other Information (Tables) | 6 Months Ended | |||||||
Jun. 30, 2014 | ||||||||
Other Information [Abstract] | ' | |||||||
Other Current Assets | ' | |||||||
Other current assets consisted of the following: | ||||||||
June 30, 2014 | December 31, 2013 | |||||||
Deposits paid to vendors | $ | 40 | $ | 49 | ||||
Prepaid and other | 226 | 261 | ||||||
Total other current assets | $ | 266 | $ | 310 | ||||
Accrued And Other Current Liabilities | ' | |||||||
Accrued and other current liabilities consisted of the following: | ||||||||
June 30, 2014 | December 31, 2013 | |||||||
Interest payable | $ | 296 | $ | 294 | ||||
Customer advances and deposits | 84 | 126 | ||||||
Accrued capital expenditures | 291 | 166 | ||||||
Accrued wages and benefits | 107 | 155 | ||||||
Taxes payable other than income taxes | 295 | 214 | ||||||
Income taxes payable | 219 | 3 | ||||||
Deferred income taxes | 152 | 119 | ||||||
Other | 238 | 351 | ||||||
Total accrued and other current liabilities | $ | 1,682 | $ | 1,428 | ||||
Reportable_Segments_Tables
Reportable Segments (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Sales Revenue, Segment [Member] | ' | |||||||||||||||
Segment Reporting Information [Line Items] | ' | |||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | |||||||||||||||
The following tables present financial information by segment: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Revenues: | ||||||||||||||||
Intrastate transportation and storage: | ||||||||||||||||
Revenues from external customers | $ | 669 | $ | 558 | $ | 1,516 | $ | 1,203 | ||||||||
Intersegment revenues | 43 | 65 | 130 | 104 | ||||||||||||
712 | 623 | 1,646 | 1,307 | |||||||||||||
Interstate transportation and storage: | ||||||||||||||||
Revenues from external customers | 245 | 354 | 540 | 677 | ||||||||||||
Intersegment revenues | 4 | 3 | 7 | 4 | ||||||||||||
249 | 357 | 547 | 681 | |||||||||||||
Midstream: | ||||||||||||||||
Revenues from external customers | 302 | 308 | 604 | 639 | ||||||||||||
Intersegment revenues | 418 | 269 | 769 | 538 | ||||||||||||
720 | 577 | 1,373 | 1,177 | |||||||||||||
NGL transportation and services: | ||||||||||||||||
Revenues from external customers | 878 | 420 | 1,679 | 766 | ||||||||||||
Intersegment revenues | 25 | 18 | 54 | 37 | ||||||||||||
903 | 438 | 1,733 | 803 | |||||||||||||
Investment in Sunoco Logistics: | ||||||||||||||||
Revenues from external customers | 4,766 | 4,256 | 9,218 | 7,713 | ||||||||||||
Intersegment revenues | 55 | 55 | 80 | 110 | ||||||||||||
4,821 | 4,311 | 9,298 | 7,823 | |||||||||||||
Retail marketing: | ||||||||||||||||
Revenues from external customers | 5,568 | 5,291 | 10,576 | 10,508 | ||||||||||||
Intersegment revenues | — | — | 3 | 5 | ||||||||||||
5,568 | 5,291 | 10,579 | 10,513 | |||||||||||||
All other: | ||||||||||||||||
Revenues from external customers | 601 | 364 | 1,128 | 899 | ||||||||||||
Intersegment revenues | 120 | 121 | 184 | 217 | ||||||||||||
721 | 485 | 1,312 | 1,116 | |||||||||||||
Eliminations | (665 | ) | (531 | ) | (1,227 | ) | (1,015 | ) | ||||||||
Total revenues | $ | 13,029 | $ | 11,551 | $ | 25,261 | $ | 22,405 | ||||||||
Operating Segments [Member] | ' | |||||||||||||||
Segment Reporting Information [Line Items] | ' | |||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | |||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Segment Adjusted EBITDA: | ||||||||||||||||
Intrastate transportation and storage | $ | 110 | $ | 112 | $ | 287 | $ | 244 | ||||||||
Interstate transportation and storage | 265 | 361 | 565 | 658 | ||||||||||||
Midstream | 157 | 127 | 283 | 214 | ||||||||||||
NGL transportation and services | 141 | 77 | 269 | 157 | ||||||||||||
Investment in Sunoco Logistics | 280 | 244 | 488 | 480 | ||||||||||||
Retail marketing | 136 | 97 | 245 | 134 | ||||||||||||
All other | 80 | 51 | 238 | 138 | ||||||||||||
Total | 1,169 | 1,069 | 2,375 | 2,025 | ||||||||||||
Depreciation and amortization | (268 | ) | (251 | ) | (534 | ) | (511 | ) | ||||||||
Interest expense, net of interest capitalized | (217 | ) | (211 | ) | (436 | ) | (422 | ) | ||||||||
Gain on sale of AmeriGas common units | 93 | — | 163 | — | ||||||||||||
Gains (losses) on interest rate derivatives | (46 | ) | 39 | (48 | ) | 46 | ||||||||||
Non-cash unit-based compensation expense | (13 | ) | (10 | ) | (27 | ) | (24 | ) | ||||||||
Unrealized gains (losses) on commodity risk management activities | (1 | ) | 18 | (30 | ) | 37 | ||||||||||
LIFO valuation adjustments | 20 | (22 | ) | 34 | 16 | |||||||||||
Adjusted EBITDA related to discontinued operations | — | (23 | ) | (27 | ) | (63 | ) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | (170 | ) | (158 | ) | (366 | ) | (323 | ) | ||||||||
Equity in earnings of unconsolidated affiliates | 57 | 37 | 136 | 109 | ||||||||||||
Other, net | (15 | ) | 5 | (18 | ) | 8 | ||||||||||
Income from continuing operations before income tax expense | $ | 609 | $ | 493 | $ | 1,222 | $ | 898 | ||||||||
Assets Segments [Member] | ' | |||||||||||||||
Segment Reporting Information [Line Items] | ' | |||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | |||||||||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||
Total assets: | ||||||||||||||||
Intrastate transportation and storage | $ | 4,504 | $ | 4,606 | ||||||||||||
Interstate transportation and storage | 10,158 | 10,988 | ||||||||||||||
Midstream | 3,307 | 3,133 | ||||||||||||||
NGL transportation and services | 4,576 | 4,326 | ||||||||||||||
Investment in Sunoco Logistics | 13,437 | 11,650 | ||||||||||||||
Retail marketing | 4,532 | 3,936 | ||||||||||||||
All other | 3,709 | 5,063 | ||||||||||||||
Total | $ | 44,223 | $ | 43,702 | ||||||||||||
Operations_And_Organization_Op
Operations And Organization Operations And Organization (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Lone Star L.L.C. [Member] | ' | ' | ' | ' |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | ' | ' | 70.00% | ' |
FEP [Member] | ' | ' | ' | ' |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | ' | ' | 50.00% | ' |
Citrus [Member] | ' | ' | ' | ' |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | ' | ' | 50.00% | ' |
Fayetteville Express Pipeline, LLC [Member] | FEP [Member] | ' | ' | ' | ' |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | ' | ' | 100.00% | ' |
Fayetteville Express Pipeline, LLC [Member] | FGT | ' | ' | ' | ' |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | ' | ' | 100.00% | ' |
Retail marketing: | ' | ' | ' | ' |
Excise Taxes Collected | $573 | $563 | $1,100 | $1,080 |
Acquisitions_Divestitures_and_1
Acquisitions, Divestitures and Related Transactions Narrative (Details) (USD $) | 6 Months Ended | 1 Months Ended | |||||||||||
Share data in Millions, unless otherwise specified | Jun. 30, 2014 | Jan. 09, 2014 | Apr. 27, 2014 | Apr. 30, 2013 | Apr. 30, 2013 | Jan. 09, 2014 | Jan. 09, 2014 | Jan. 09, 2014 | Feb. 28, 2014 | Apr. 30, 2014 | Apr. 27, 2014 | Jan. 09, 2014 | Jan. 09, 2014 |
Susser Merger [Member] | Southern Union [Member] | ETP [Member] | Panhandle [Member] | 7.60% Senior Notes, due February 1, 2024 [Member] | 8.25% Senior Notes, due November 14, 2029 [Member] | Trunkline LNG Transaction [Member] | Common Units [Member] | Common Units [Member] | Common Units [Member] | Class F Units [Member] | |||
SUGS Contribution [Member] | SUGS Contribution [Member] | ETP [Member] | Susser Petroleum [Member] | Susser Petroleum [Member] | Panhandle [Member] | Panhandle [Member] | |||||||
Susser Merger [Member] | Susser Merger [Member] | Regency | Regency | ||||||||||
SUGS Contribution [Member] | SUGS Contribution [Member] | ||||||||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Combination, Cost of Acquired Entity, Purchase Price | ' | ' | $1,800,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common Units Representing An Aggregate Limited Partner Interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.20% | ' | ' |
Number of Stores | ' | ' | 630 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | ' | ' | ' | ' | ' | 2.2 | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | ' | 7.60% | 8.25% | ' | ' | ' | ' | ' |
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 31.4 | 6.3 |
Common Units redeemed in connection with the Trunkline LNG Transaction | ' | ' | ' | ' | ' | ' | ' | ' | 18.7 | ' | ' | ' | ' |
Goodwill, Written off Related to Sale of Business Unit | ' | ' | ' | ' | ' | ' | ' | ' | 184,000,000 | ' | ' | ' | ' |
Indefinite-lived Intangible Assets, Written off Related to Sale of Business Unit | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' |
Related Party Transaction, Amounts of Transaction | ' | ' | ' | ' | ' | ' | ' | ' | 75,000,000 | ' | ' | ' | ' |
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11 | ' | ' | ' |
Guarantor Obligations, Current Carrying Value | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents | ' | ' | ' | 463,000,000 | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax | $39,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash_And_Cash_Equivalents_Net_
Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) (USD $) | 6 Months Ended | |
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 |
Cash and Cash Equivalents [Abstract] | ' | ' |
Accounts receivable | ($778) | ($206) |
Accounts receivable from related companies | -90 | -63 |
Inventories | 310 | -64 |
Exchanges receivable | -31 | -5 |
Other current assets | 193 | 72 |
Other non-current assets, net | -25 | -32 |
Accounts payable | 563 | 177 |
Accounts payable to related companies | 47 | -65 |
Exchanges payable | -12 | -2 |
Accrued and other current liabilities | 147 | 48 |
Other non-current liabilities | -44 | -34 |
Price risk management assets and liabilities, net | 71 | -103 |
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $351 | ($277) |
Cash_And_Cash_Equivalents_NonC
Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) (USD $) | 6 Months Ended | |
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 |
NON-CASH INVESTING ACTIVITIES: | ' | ' |
Accrued capital expenditures | $291 | $405 |
Net gains from subsidiary common unit issuances | 14 | 0 |
NON-CASH FINANCING ACTIVITIES: | ' | ' |
Redemption of Common Units in connection with the Trunkline LNG Transaction (see Note 2) | -1,167 | ' |
SUGS Contribution [Member] | ' | ' |
NON-CASH INVESTING ACTIVITIES: | ' | ' |
Regency common units and Class F units received in exchange for contribution of SUGS | 0 | 961 |
Holdco Acquisition [Member] | ' | ' |
NON-CASH FINANCING ACTIVITIES: | ' | ' |
Issuance of Common Units in connection with the Holdco Acquisition | 0 | 2,464 |
Trunkline LNG Transaction [Member] | ' | ' |
NON-CASH FINANCING ACTIVITIES: | ' | ' |
Redemption of Common Units in connection with the Trunkline LNG Transaction (see Note 2) | $1,167 | $0 |
Inventories_Inventory_Schedule
Inventories Inventory Schedule (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Inventory, Gross [Abstract] | ' | ' |
Natural gas and NGLs | $258 | $519 |
Crude oil | 478 | 488 |
Refined products | 583 | 597 |
Appliances, parts and fittings and other | 177 | 161 |
Total inventories | $1,496 | $1,765 |
Advances_to_and_Investments_in1
Advances to and Investments in Unconsolidated Affiliates Narrative (Details) (USD $) | 0 Months Ended | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Aug. 01, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Aug. 01, 2014 | Jun. 30, 2014 |
AmeriGas [Member] | AmeriGas [Member] | AmeriGas [Member] | AmeriGas [Member] | Bayview Refining Company, LLC [Member] | |
AmeriGas common units sold by ETP | 1.2 | 8.5 | 9.2 | ' | ' |
Equity Method Investment, Net Sales Proceeds | $55 | $377 | $381 | ' | ' |
Investment Owned, Balance, Shares | ' | ' | ' | 3.1 | ' |
Equity Method Investment, Ownership Percentage | ' | ' | ' | ' | 49.00% |
Advances to affiliates, net of repayments | ' | ' | ' | ' | $8 |
Fair_Value_Measurements_Narrat
Fair Value Measurements Narrative (Details) (USD $) | 6 Months Ended | |
In Billions, unless otherwise specified | Jun. 30, 2014 | Dec. 31, 2013 |
Fair Value Measurements [Abstract] | ' | ' |
Transfers between levels in fair value hierarchy | $0 | ' |
Aggregate fair value of long-term debt | 19.12 | 17.69 |
Aggregate carrying amount of long-term debt | $17.57 | $17.09 |
Fair_Value_Measurements_Fair_V
Fair Value Measurements Fair Value of Assets and Liabilities (Details) (Fair Value, Measurements, Recurring [Member], USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Interest rate derivatives, Assets | $3 | $47 |
Total commodity derivatives, Assets | 68 | 227 |
Total Assets | 71 | 274 |
Interest rate derivatives, Liabilities | -121 | -95 |
Total commodity derivatives, Liabilities | -82 | -223 |
Total Liabilities | -203 | -318 |
Level 1 | ' | ' |
Interest rate derivatives, Assets | 0 | 0 |
Total commodity derivatives, Assets | 60 | 217 |
Total Assets | 60 | 217 |
Interest rate derivatives, Liabilities | 0 | 0 |
Total commodity derivatives, Liabilities | -76 | -215 |
Total Liabilities | -76 | -215 |
Level 2 | ' | ' |
Interest rate derivatives, Assets | 3 | 47 |
Total commodity derivatives, Assets | 8 | 10 |
Total Assets | 11 | 57 |
Interest rate derivatives, Liabilities | -121 | -95 |
Total commodity derivatives, Liabilities | -6 | -8 |
Total Liabilities | -127 | -103 |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ' | ' |
Total commodity derivatives, Assets | 7 | 5 |
Total commodity derivatives, Liabilities | -7 | -4 |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Level 1 | ' | ' |
Total commodity derivatives, Assets | 7 | 5 |
Total commodity derivatives, Liabilities | -7 | -4 |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Level 2 | ' | ' |
Total commodity derivatives, Assets | 0 | 0 |
Total commodity derivatives, Liabilities | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | ' | ' |
Total commodity derivatives, Assets | 2 | 8 |
Total commodity derivatives, Liabilities | -2 | -6 |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Level 1 | ' | ' |
Total commodity derivatives, Assets | 2 | 1 |
Total commodity derivatives, Liabilities | -2 | 0 |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Level 2 | ' | ' |
Total commodity derivatives, Assets | 0 | 7 |
Total commodity derivatives, Liabilities | 0 | -6 |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | ' | ' |
Total commodity derivatives, Assets | 35 | 201 |
Total commodity derivatives, Liabilities | -42 | -201 |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Level 1 | ' | ' |
Total commodity derivatives, Assets | 35 | 201 |
Total commodity derivatives, Liabilities | -42 | -201 |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Level 2 | ' | ' |
Total commodity derivatives, Assets | 0 | 0 |
Total commodity derivatives, Liabilities | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | ' | ' |
Total commodity derivatives, Liabilities | ' | 1 |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Level 1 | ' | ' |
Total commodity derivatives, Liabilities | ' | 0 |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Level 2 | ' | ' |
Total commodity derivatives, Liabilities | ' | 1 |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | ' | ' |
Total commodity derivatives, Assets | 8 | 3 |
Total commodity derivatives, Liabilities | -6 | -1 |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Level 1 | ' | ' |
Total commodity derivatives, Assets | 0 | 0 |
Total commodity derivatives, Liabilities | 0 | 0 |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Level 2 | ' | ' |
Total commodity derivatives, Assets | 8 | 3 |
Total commodity derivatives, Liabilities | -6 | -1 |
Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member] | ' | ' |
Total commodity derivatives, Assets | 4 | ' |
Total commodity derivatives, Liabilities | -4 | ' |
Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member] | Level 1 | ' | ' |
Total commodity derivatives, Assets | 4 | ' |
Total commodity derivatives, Liabilities | -4 | ' |
Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member] | Level 2 | ' | ' |
Total commodity derivatives, Assets | 0 | ' |
Total commodity derivatives, Liabilities | 0 | ' |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | ' | ' |
Total commodity derivatives, Assets | 7 | 5 |
Total commodity derivatives, Liabilities | -14 | -5 |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Level 1 | ' | ' |
Total commodity derivatives, Assets | 7 | 5 |
Total commodity derivatives, Liabilities | -14 | -5 |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Level 2 | ' | ' |
Total commodity derivatives, Assets | 0 | 0 |
Total commodity derivatives, Liabilities | 0 | 0 |
Commodity Derivatives - Refined Products [Member] | Fixed Swaps/Futures [Member] | ' | ' |
Total commodity derivatives, Assets | 5 | 5 |
Total commodity derivatives, Liabilities | -7 | -5 |
Commodity Derivatives - Refined Products [Member] | Fixed Swaps/Futures [Member] | Level 1 | ' | ' |
Total commodity derivatives, Assets | 5 | 5 |
Total commodity derivatives, Liabilities | -7 | -5 |
Commodity Derivatives - Refined Products [Member] | Fixed Swaps/Futures [Member] | Level 2 | ' | ' |
Total commodity derivatives, Assets | 0 | 0 |
Total commodity derivatives, Liabilities | $0 | $0 |
Net_Income_Per_Limited_Partner2
Net Income Per Limited Partner Unit Reconciliation of Net Income and Weighted Avg Units Used in Computing Basic and Diluted EPU (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Earnings Per Share [Abstract] | ' | ' | ' | ' |
Income from continuing operations | $539 | $404 | $1,006 | $806 |
Less: Income from continuing operations attributable to noncontrolling interest | 110 | 89 | 186 | 178 |
Income from continuing operations, net of noncontrolling interest | 429 | 315 | 820 | 628 |
General Partner’s interest in income from continuing operations | 125 | 154 | 238 | 282 |
Class H Unitholder’s interest in income from continuing operations | 51 | 0 | 100 | 0 |
Common Unitholders’ interest in income from continuing operations | 253 | 161 | 482 | 346 |
Additional earnings allocated from (to) General Partner | 1 | 23 | -2 | 0 |
Distributions on employee unit awards, net of allocation to General Partner | -3 | -2 | -6 | -5 |
Income from continuing operations available to Common Unitholders | $251 | $182 | $474 | $341 |
Weighted average Common Units – basic | 318.5 | 352.6 | 321.4 | 326.9 |
Basic income from continuing operations per Common Unit | $0.79 | $0.52 | $1.47 | $1.04 |
Dilutive effect of unvested Unit Awards | 1 | 1.2 | 1 | 1.2 |
Weighted average Common Units, assuming dilutive effect of unvested Unit Awards | 319.5 | 353.8 | 322.4 | 328.1 |
Diluted income from continuing operations per Common Unit | $0.79 | $0.52 | $1.47 | $1.04 |
Basic income from discontinued operations per Common Unit | $0.13 | $0.01 | $0.20 | $0.04 |
Diluted income from discontinued operations per Common Unit | $0.13 | $0.01 | $0.20 | $0.04 |
Debt_Obligations_Narrative_Det
Debt Obligations Narrative (Details) (USD $) | Jun. 30, 2014 |
ETP [Member] | ETP Revolving Credit Facility, due October 2017 [Member] | ' |
Line of Credit Facility, Current Borrowing Capacity | $2,500,000,000 |
Line of Credit Facility, Amount Outstanding | 0 |
Investment in Sunoco Logistics: | 4.25% Senior Notes due April 2024 [Member] | ' |
Senior notes, aggregate principal amount | 300,000,000 |
Debt Instrument, Interest Rate, Stated Percentage | 4.25% |
Investment in Sunoco Logistics: | 5.30% Senior Notes due April 2044 [Member] | ' |
Senior notes, aggregate principal amount | 700,000,000 |
Debt Instrument, Interest Rate, Stated Percentage | 5.30% |
Investment in Sunoco Logistics: | Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 19, 2018 [Member] | ' |
Line of Credit Facility, Current Borrowing Capacity | 1,500,000,000 |
Line of Credit Facility, Amount Outstanding | 250,000,000 |
Line of Credit Facility, Maximum Borrowing Capacity | $2,250,000,000 |
Equity_Narrative_Details
Equity Narrative (Details) (USD $) | 6 Months Ended | 12 Months Ended | ||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Net gains from subsidiary common unit issuances | ' | $14 | $0 | ' | ' | ' | ' | ' |
Relinquishment of Rights of Incentive Distributions | 53 | 53 | ' | 35 | 45 | 50 | 72 | 51 |
ETP [Member] | ' | ' | ' | ' | ' | ' | ' | ' |
Stock Issued During Period, Value, Dividend Reinvestment Plan | ' | 67 | ' | ' | ' | ' | ' | ' |
Common Units issued in connection with the Distribution Reinvestment Plan | ' | 1.3 | ' | ' | ' | ' | ' | ' |
Equity Distribution Reinvestment Program, Capacity, Shares | ' | 0.8 | ' | ' | ' | ' | ' | ' |
Equity Distribution Agreement [Member] | Investment in Sunoco Logistics: | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Issuance of Common Stock | ' | 102 | ' | ' | ' | ' | ' | ' |
Fees and Commissions | ' | 1 | ' | ' | ' | ' | ' | ' |
Equity Distribution Agreements, Value of Units Available to be Issued | ' | 147 | ' | ' | ' | ' | ' | ' |
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units | ' | 250 | ' | ' | ' | ' | ' | ' |
Equity Distribution Agreement [Member] | ETP [Member] | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Issuance of Common Stock | ' | 417 | ' | ' | ' | ' | ' | ' |
Fees and Commissions | ' | 4 | ' | ' | ' | ' | ' | ' |
Equity Distribution Agreements, Value of Units Available to be Issued | ' | 725 | ' | ' | ' | ' | ' | ' |
Trunkline LNG Transaction [Member] | ETP [Member] | ' | ' | ' | ' | ' | ' | ' | ' |
Common Units redeemed in connection with the Trunkline LNG Transaction | ' | 18.7 | ' | ' | ' | ' | ' | ' |
Susser Merger [Member] | ' | ' | ' | ' | ' | ' | ' | ' |
Relinquishment of Rights of Incentive Distributions | ' | $350 | ' | ' | ' | ' | ' | ' |
Equity_Common_Unit_Activity_De
Equity Common Unit Activity (Details) | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 |
In Millions, unless otherwise specified | ETP [Member] | ETP [Member] | ||
Trunkline LNG Transaction [Member] | ||||
Number of Common Units at December 31, 2013 | 324 | 333.8 | ' | ' |
Common Units issued in connection with Equity Distribution Agreements | ' | ' | 7.6 | ' |
Common Units issued in connection with the Distribution Reinvestment Plan | ' | ' | 1.3 | ' |
Common Units redeemed in connection with the Trunkline LNG Transaction | ' | ' | ' | -18.7 |
Number of Common Units at June 30, 2014 | 324 | 333.8 | ' | ' |
Equity_Quarterly_Distributions
Equity Quarterly Distributions Of Available Cash (Details) (USD $) | 3 Months Ended | ||
Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | |
ETP [Member] | ' | ' | ' |
Distribution Made to Member or Limited Partner [Line Items] | ' | ' | ' |
Record Date | 4-Aug-14 | 5-May-14 | 7-Feb-14 |
Payment Date | 14-Aug-14 | 15-May-14 | 14-Feb-14 |
Rate | $0.96 | $0.94 | $0.92 |
Investment in Sunoco Logistics: | ' | ' | ' |
Distribution Made to Member or Limited Partner [Line Items] | ' | ' | ' |
Record Date | 8-Aug-14 | 9-May-14 | 10-Feb-14 |
Payment Date | 14-Aug-14 | 15-May-14 | 14-Feb-14 |
Rate | $0.37 | $0.35 | $0.33 |
Equity_Net_IDR_Schedule_Detail
Equity Net IDR Schedule (Details) (USD $) | 6 Months Ended | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Jun. 30, 2014 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Equity [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Relinquishment of Rights of Incentive Distributions | $53 | $53 | $35 | $45 | $50 | $72 | $51 |
Equity_Accumulated_Other_Compr
Equity Accumulated Other Comprehensive Income, Net Of Tax (Details) (USD $) | 6 Months Ended | 12 Months Ended |
In Millions, unless otherwise specified | Jun. 30, 2014 | Dec. 31, 2013 |
Partners' Capital Notes [Abstract] | ' | ' |
Available-for-sale securities | $2 | $2 |
Foreign currency translation adjustment | -3 | -1 |
Net loss on commodity related hedges | -4 | -4 |
Actuarial gain related to pensions and other postretirement benefits | 55 | 56 |
Investments in unconsolidated affiliates, net | 2 | 8 |
Total AOCI, net of tax | $52 | $61 |
Income_Taxes_Narrative_Details
Income Taxes Narrative (Details) (Trunkline LNG, USD $) | 6 Months Ended |
In Millions, unless otherwise specified | Jun. 30, 2014 |
Trunkline LNG | ' |
Investments, Owned, Federal Income Tax Note [Line Items] | ' |
Incremental Income Tax Related to a Transaction | $87 |
Retirement_Benefits_Details
Retirement Benefits (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Pension Benefits | ' | ' | ' | ' |
Net periodic benefit cost: | ' | ' | ' | ' |
Service cost | $1 | $3 | $1 | $5 |
Interest cost | 7 | 9 | 15 | 18 |
Expected return on plan assets | -9 | -15 | -20 | -30 |
Actuarial loss amortization | ' | ' | -1 | 1 |
Settlement credits | -1 | 0 | -2 | -2 |
Net periodic benefit cost subtotal | -2 | -3 | -7 | -8 |
Regulatory adjustment | 0 | 2 | 0 | 4 |
Net periodic benefit cost | -2 | -1 | -7 | -4 |
Other Postretirement Benefits | ' | ' | ' | ' |
Net periodic benefit cost: | ' | ' | ' | ' |
Service cost | 0 | 1 | 0 | 1 |
Interest cost | 2 | 1 | 3 | 3 |
Expected return on plan assets | -2 | -1 | -4 | -4 |
Actuarial loss amortization | ' | ' | 0 | 0 |
Settlement credits | 0 | 0 | 0 | 0 |
Net periodic benefit cost subtotal | 0 | 1 | -1 | 0 |
Regulatory adjustment | 0 | 0 | 0 | 0 |
Net periodic benefit cost | $0 | $1 | ($1) | $0 |
Regulatory_Matters_Commitments2
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details) (USD $) | 3 Months Ended | 6 Months Ended | 1 Months Ended | 3 Months Ended | 6 Months Ended | 1 Months Ended | ||||||||||
Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Jan. 09, 2014 | Dec. 31, 2013 | Nov. 30, 2012 | Jan. 31, 2012 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Apr. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | |
FGT | AmeriGas [Member] | Sunoco [Member] | Sunoco [Member] | Sunoco [Member] | Sunoco [Member] | Regency 4.50% Senior Notes Due 2023 [Member] | Attorney General of Commonwealth [Member] | I-595 Project [Member] | Turnpike/State Road 91 [Member] | |||||||
FGT | FGT | |||||||||||||||
Proceeds from Legal Settlements | ' | ' | ' | ' | ' | ' | $100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency, Damages Awarded, Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | 1,000,000 |
Contingent Residual Support Agreement, Amount | ' | ' | ' | ' | ' | ' | ' | 1,550,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Guarantor Obligations, Current Carrying Value | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.50% | ' | ' | ' |
Maximum lease expiration year | ' | ' | 31-Dec-56 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Rent Expense, Contingent Rentals | 6,000,000 | 6,000,000 | 9,000,000 | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss contingency accrual, at carrying value | 43,000,000 | ' | 43,000,000 | ' | ' | 46,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Legal Fees | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | ' | ' |
Percentage Of Recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' |
Reimbursement expert and consultant cost, maximum | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 150,000 | ' | ' |
Sites where remediation operations are responsibility of third parties | ' | ' | ' | ' | ' | ' | ' | ' | 40 | ' | 40 | ' | ' | ' | ' | ' |
Payments for Environmental Liabilities | ' | ' | ' | ' | ' | ' | ' | ' | $9,000,000 | $8,000,000 | $17,000,000 | $15,000,000 | ' | ' | ' | ' |
Regulatory_Matters_Commitments3
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Operating Leases, Rental Expense (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Rental expense(1) | $25 | $30 | $56 | $62 |
Less: Sublease rental income | -10 | -5 | -18 | -10 |
Rental expense, net | $15 | $25 | $38 | $52 |
Regulatory_Matters_Commitments4
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Environmental Exit Cost [Line Items] | ' | ' |
Current | $71 | $45 |
Non-current | 319 | 350 |
Total environmental liabilities | $390 | $395 |
Price_Risk_Management_Assets_A2
Price Risk Management Assets And Liabilities Narrative (Details) (ETP [Member], USD $) | Jun. 30, 2014 |
In Millions, unless otherwise specified | |
ETP [Member] | ' |
Derivative [Line Items] | ' |
Price Risk Cash Flow Hedge Unrealized Gain (Loss) to be Reclassified During Next 12 Months | ($3) |
Price_Risk_Management_Assets_A3
Price Risk Management Assets And Liabilities Outstanding Commodity-Related Derivatives (Details) | 6 Months Ended | 12 Months Ended |
Jun. 30, 2014 | Dec. 31, 2013 | |
Megawatt | Megawatt | |
Options - Puts [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | -54,400 | -52,800 |
Term Of Commodity Derivatives | '2014 | '2014 |
Options - Calls [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | 54,400 | 103,200 |
Term Of Commodity Derivatives | '2014 | '2014 |
Forwards Swaps [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | 270,150 | 351,050 |
Term Of Commodity Derivatives | '2014 | '2014 |
Future [Member] | Crude Oil [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | -40,000 | 103,000 |
Term Of Commodity Derivatives | '2014 | '2014 |
Future [Member] | Crude Oil [Member] | Cash Flow Hedging Derivatives [Member] | ' | ' |
Notional Volume | 0 | -30,000 |
Term Of Commodity Derivatives | ' | '2014 |
Future [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | 10,670 | -772,476 |
Term Of Commodity Derivatives | '2014 | '2014 |
Non Trading [Member] | Future [Member] | Refined Products [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | -1,605,000 | -280,000 |
Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | 0 | 9,457,500 |
Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | 16,632,500 | -487,500 |
Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | 0 | 1,937,500 |
Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | -4,445,000 | -8,195,000 |
Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member] | Fair Value Hedging Derivatives [Member] | ' | ' |
Notional Volume | -1,757,500 | -50,530,000 |
Term Of Commodity Derivatives | '2014 | '2014 |
Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member] | Cash Flow Hedging Derivatives [Member] | ' | ' |
Notional Volume | -6,440,000 | -12,775,000 |
Term Of Commodity Derivatives | '2014 | '2014 |
Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | -2,537,500 | 570,000 |
Term Of Commodity Derivatives | ' | '2014 |
Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Fair Value Hedging Derivatives [Member] | ' | ' |
Notional Volume | 0 | -7,352,500 |
Term Of Commodity Derivatives | ' | '2014 |
Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Cash Flow Hedging Derivatives [Member] | ' | ' |
Notional Volume | -920,000 | -1,825,000 |
Term Of Commodity Derivatives | '2014 | '2014 |
Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Natural Gas [Member] | Fair Value Hedging Derivatives [Member] | ' | ' |
Notional Volume | 1,757,500 | 50,530,000 |
Term Of Commodity Derivatives | '2014 | '2014 |
Non Trading [Member] | Forwards Swaps [Member] | NGL [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | -1,823,200 | -1,133,600 |
Term Of Commodity Derivatives | ' | '2014 |
Non Trading [Member] | Forwards Swaps [Member] | NGL [Member] | Cash Flow Hedging Derivatives [Member] | ' | ' |
Notional Volume | -510,000 | -780,000 |
Term Of Commodity Derivatives | '2014 | '2014 |
Non Trading [Member] | Forwards Swaps [Member] | Refined Products [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | ' | '2014 |
Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | 26,147,500 | -9,690,000 |
Non Trading [Member] | Forward Physical Contracts [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Notional Volume | -5,908,374 | 5,668,559 |
Minimum [Member] | ETP [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | ' | '2014 |
Minimum [Member] | ETP [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2014 | '2014 |
Minimum [Member] | ETP [Member] | Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | ' | '2014 |
Minimum [Member] | ETP [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2014 | '2014 |
Minimum [Member] | ETP [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2014 | ' |
Minimum [Member] | ETP [Member] | Non Trading [Member] | Forwards Swaps [Member] | NGL [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2014 | ' |
Minimum [Member] | ETP [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2014 | '2014 |
Minimum [Member] | ETP [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2014 | '2014 |
Minimum [Member] | ETP [Member] | Non Trading [Member] | Future [Member] | Refined Products [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2014 | ' |
Maximum [Member] | ETP [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | ' | '2019 |
Maximum [Member] | ETP [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2015 | '2017 |
Maximum [Member] | ETP [Member] | Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | ' | '2016 |
Maximum [Member] | ETP [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2019 | '2015 |
Maximum [Member] | ETP [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2015 | ' |
Maximum [Member] | ETP [Member] | Non Trading [Member] | Forwards Swaps [Member] | NGL [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2015 | ' |
Maximum [Member] | ETP [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2015 | '2016 |
Maximum [Member] | ETP [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2015 | '2015 |
Maximum [Member] | ETP [Member] | Non Trading [Member] | Future [Member] | Refined Products [Member] | Mark-To-Market Derivatives [Member] | ' | ' |
Term Of Commodity Derivatives | '2015 | ' |
Price_Risk_Management_Assets_A4
Price Risk Management Assets And Liabilities Interest Rate Swaps Outstanding (Details) (Interest rate derivatives, USD $) | 6 Months Ended | |||
In Millions, unless otherwise specified | Jun. 30, 2014 | Dec. 31, 2013 | ||
July 2014 [Member] | ETP [Member] | ' | ' | ||
Notional Amount | $300 | [1] | $400 | [1] |
Type | 'Forward-starting to pay a fixed rate of 4.15% and receive a floating rate | [1],[2] | ' | |
July 2015 [Member] | ETP [Member] | ' | ' | ||
Notional Amount | 200 | [1] | 0 | [1] |
Type | 'Forward-starting to pay a fixed rate of 3.38% and receive a floating rate | [1],[2] | ' | |
July 2016 [Member] | ETP [Member] | ' | ' | ||
Notional Amount | 200 | [3] | 0 | [3] |
Type | 'Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | [2],[3] | ' | |
July 2017 [Member] | ETP [Member] | ' | ' | ||
Notional Amount | 200 | [4] | 0 | [4] |
Type | 'Forward-starting to pay a fixed rate of 4.18% and receive a floating rate | [2],[4] | ' | |
Forward Starting July 2018 [Member] | ETP [Member] | ' | ' | ||
Notional Amount | 200 | [4] | 0 | [4] |
Type | 'Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | [2],[4] | ' | |
July 2018 [Member] | ETP [Member] | ' | ' | ||
Notional Amount | 0 | 600 | ||
Type | 'Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% | [2] | ' | |
June 2021 [Member] | ETP [Member] | ' | ' | ||
Notional Amount | 0 | 400 | ||
Type | 'Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% | [2] | ' | |
February 2023 [Member] | ETP [Member] | ' | ' | ||
Notional Amount | 200 | 400 | ||
Type | 'Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | [2] | ' | |
November 2021 [Member] | Panhandle [Member] | ' | ' | ||
Notional Amount | $275 | $275 | ||
Type | 'Pay a fixed rate of 3.80% and receive a floating rate | [2] | ' | |
[1] | (2)Â Represents the effective date. These forward-starting swaps have terms of 10 years with a mandatory termination date the same as the effective date. | |||
[2] | (1)Â Floating rates are based on 3-month LIBOR. | |||
[3] | (3)Â 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)Â 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_A5
Price Risk Management Assets And Liabilities Fair Value of Derivative Instruments (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Total derivatives assets | $110 | $316 |
Total derivatives liabilities | -242 | -360 |
Designated as Hedging Instrument [Member] | ' | ' |
Total derivatives assets | 1 | 3 |
Total derivatives liabilities | -4 | -18 |
Not Designated as Hedging Instrument [Member] | ' | ' |
Total derivatives assets | 109 | 313 |
Total derivatives liabilities | -238 | -342 |
Commodity derivatives (margin deposits) | Designated as Hedging Instrument [Member] | ' | ' |
Total derivatives assets | 1 | 3 |
Total derivatives liabilities | -4 | -18 |
Commodity derivatives (margin deposits) | Not Designated as Hedging Instrument [Member] | ' | ' |
Total derivatives assets | 59 | 227 |
Total derivatives liabilities | -73 | -209 |
Commodity derivatives | Not Designated as Hedging Instrument [Member] | ' | ' |
Total derivatives assets | 47 | 39 |
Total derivatives liabilities | -44 | -38 |
Interest rate derivatives | Not Designated as Hedging Instrument [Member] | ' | ' |
Total derivatives assets | 3 | 47 |
Total derivatives liabilities | ($121) | ($95) |
Price_Risk_Management_Assets_A6
Price Risk Management Assets And Liabilities Fair Value of Derivatives, Netting Basis (Details) (USD $) | 3 Months Ended | 6 Months Ended | |||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) Recognized in Income, Net | ($83) | $65 | ($71) | $45 | ' |
Derivative Asset, Fair Value, Gross Asset | 110 | ' | 110 | ' | 316 |
Derivative Liability, Fair Value, Gross Liability | -242 | ' | -242 | ' | -360 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | -46 | ' | -46 | ' | -37 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 73 | ' | 73 | ' | 91 |
Netting [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Asset, Fair Value, Gross Asset | 153 | ' | 153 | ' | 306 |
Derivative Liability, Fair Value, Gross Liability | 194 | ' | 194 | ' | 356 |
Derivative Asset, Fair Value, Gross Liability | -38 | ' | -38 | ' | -36 |
Derivative Liability, Fair Value, Gross Asset | 38 | ' | 38 | ' | 36 |
Derivative Asset, Fair Value, Net | 107 | ' | 107 | ' | 269 |
Derivative Liability, Fair Value, Net | -121 | ' | -121 | ' | -265 |
Bi-lateral contracts [Member] | Netting [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Asset, Fair Value, Gross Asset | 47 | ' | 47 | ' | 41 |
Derivative Liability, Fair Value, Gross Liability | 44 | ' | 44 | ' | 38 |
Broker cleared derivative contracts [Member] | Netting [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Asset, Fair Value, Gross Asset | 106 | ' | 106 | ' | 265 |
Derivative Liability, Fair Value, Gross Liability | 150 | ' | 150 | ' | 318 |
Asset Fair Value, Netting Offset [Member] | Netting [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Payments on Margin Deposits | -8 | ' | -8 | ' | -1 |
Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value | 3 | ' | 3 | ' | 47 |
Liability Fair Value, Netting Offset [Member] | Netting [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Payments on Margin Deposits | 35 | ' | 35 | ' | 55 |
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value | ($121) | ' | ($121) | ' | ($95) |
Price_Risk_Management_Assets_A7
Price Risk Management Assets And Liabilities Partnership's Derivative Assets And Liabilities, Recognized OCI On Derivatives (Effective Portion) (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Change in Value Recognized in OCI on Derivatives (Effective Portion) | ($2) | $6 | ($6) | $8 |
Derivatives In Cash Flow Hedging Relationships - Commodity Derivatives [Member] | ' | ' | ' | ' |
Change in Value Recognized in OCI on Derivatives (Effective Portion) | ($2) | $6 | ($6) | $8 |
Price_Risk_Management_Assets_A8
Price Risk Management Assets And Liabilities Partnership's Derivative Assets And Liabilities, Amount Of Gain/(Loss) Reclassified From AOCI Into Income (Effective Portion) (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | ($2) | $1 | ($6) | $2 |
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness | 0 | -1 | -6 | 4 |
Amount of Gain (Loss) Recognized In Income On Derivatives | -83 | 65 | -71 | 45 |
Gains (losses) on interest rate derivatives | -46 | 39 | -48 | 46 |
Commodity Derivatives - Trading [Member] | ' | ' | ' | ' |
Amount of Gain (Loss) Recognized In Income On Derivatives | -5 | 3 | 2 | -1 |
Commodity derivatives | ' | ' | ' | ' |
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | -2 | 1 | -6 | 2 |
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness | 0 | -1 | -6 | 4 |
Amount of Gain (Loss) Recognized In Income On Derivatives | -32 | 21 | -25 | 3 |
Commodity derivatives | Deferred Gas Purchases [Member] | ' | ' | ' | ' |
Amount of Gain (Loss) Recognized In Income On Derivatives | $0 | $2 | $0 | ($3) |
Related_Party_Transactions_Nar
Related Party Transactions Narrative (Details) (Trunkline LNG Transaction [Member], USD $) | 1 Months Ended |
In Millions, unless otherwise specified | Feb. 28, 2014 |
Trunkline LNG Transaction [Member] | ' |
Related Party Transaction, Amounts of Transaction | $75 |
Related_Party_Transactions_Aff
Related Party Transactions Affiliated Revenue (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Related Party Transactions [Abstract] | ' | ' | ' | ' |
Affiliated revenues | $390 | $333 | $731 | $715 |
Related_Party_Transactions_Rel
Related Party Transactions Related Party A/R and A/P (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Accounts Receivable, Related Parties, Current | $255 | $165 |
Accounts Payable, Related Parties, Current | 88 | 45 |
ETE | ' | ' |
Accounts Receivable, Related Parties, Current | 64 | 18 |
Accounts Payable, Related Parties, Current | 3 | 8 |
Regency | ' | ' |
Accounts Receivable, Related Parties, Current | 62 | 53 |
Accounts Payable, Related Parties, Current | 55 | 24 |
PES | ' | ' |
Accounts Receivable, Related Parties, Current | 6 | 7 |
Accounts Payable, Related Parties, Current | 16 | 0 |
FGT | ' | ' |
Accounts Receivable, Related Parties, Current | 14 | 29 |
Accounts Payable, Related Parties, Current | 2 | 8 |
ET Crude Oil | ' | ' |
Accounts Receivable, Related Parties, Current | 24 | 24 |
Trunkline LNG | ' | ' |
Accounts Receivable, Related Parties, Current | 30 | 0 |
Accounts Payable, Related Parties, Current | 10 | 0 |
Other | ' | ' |
Accounts Receivable, Related Parties, Current | 55 | 34 |
Accounts Payable, Related Parties, Current | $2 | $5 |
Other_Information_Other_Curren
Other Information Other Current Assets (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Other Information [Abstract] | ' | ' |
Deposits paid to vendors | $40 | $49 |
Prepaid and other | 226 | 261 |
Total other current assets | $266 | $310 |
Other_Information_Accrued_and_
Other Information Accrued and Other Current Liabilities (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Other Information [Abstract] | ' | ' |
Interest payable | $296 | $294 |
Customer advances and deposits | 84 | 126 |
Accrued capital expenditures | 291 | 166 |
Accrued wages and benefits | 107 | 155 |
Taxes payable other than income taxes | 295 | 214 |
Income taxes payable | 219 | 3 |
Deferred income taxes | 152 | 119 |
Other | 238 | 351 |
Total accrued and other current liabilities | $1,682 | $1,428 |
Reportable_Segments_Segment_Re
Reportable Segments Segment Revenues (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | $13,029 | $11,551 | $25,261 | $22,405 |
Intrastate transportation and storage: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 712 | 623 | 1,646 | 1,307 |
Interstate transportation and storage: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 249 | 357 | 547 | 681 |
Midstream: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 720 | 577 | 1,373 | 1,177 |
NGL transportation and services: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 903 | 438 | 1,733 | 803 |
Investment in Sunoco Logistics: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 4,821 | 4,311 | 9,298 | 7,823 |
Retail marketing: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 5,568 | 5,291 | 10,579 | 10,513 |
All other: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 721 | 485 | 1,312 | 1,116 |
Eliminations | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | -665 | -531 | -1,227 | -1,015 |
Revenues from external customers | Intrastate transportation and storage: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 669 | 558 | 1,516 | 1,203 |
Revenues from external customers | Interstate transportation and storage: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 245 | 354 | 540 | 677 |
Revenues from external customers | Midstream: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 302 | 308 | 604 | 639 |
Revenues from external customers | NGL transportation and services: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 878 | 420 | 1,679 | 766 |
Revenues from external customers | Investment in Sunoco Logistics: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 4,766 | 4,256 | 9,218 | 7,713 |
Revenues from external customers | Retail marketing: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 5,568 | 5,291 | 10,576 | 10,508 |
Revenues from external customers | All other: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 601 | 364 | 1,128 | 899 |
Intersegment revenues | Intrastate transportation and storage: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 43 | 65 | 130 | 104 |
Intersegment revenues | Interstate transportation and storage: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 4 | 3 | 7 | 4 |
Intersegment revenues | Midstream: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 418 | 269 | 769 | 538 |
Intersegment revenues | NGL transportation and services: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 25 | 18 | 54 | 37 |
Intersegment revenues | Investment in Sunoco Logistics: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 55 | 55 | 80 | 110 |
Intersegment revenues | Retail marketing: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | 0 | 0 | 3 | 5 |
Intersegment revenues | All other: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues from external customers | $120 | $121 | $184 | $217 |
Reportable_Segments_Segment_Ad
Reportable Segments Segment Adjusted EBITDA (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Segment Adjusted EBITDA: | $1,169 | $1,069 | $2,375 | $2,025 |
Depreciation and amortization | -268 | -251 | -534 | -511 |
Interest expense, net of interest capitalized | -217 | -211 | -436 | -422 |
Gain on sale of AmeriGas common units | 93 | 0 | 163 | 0 |
Gains (losses) on interest rate derivatives | -46 | 39 | -48 | 46 |
Non-cash unit-based compensation expense | -13 | -10 | -27 | -24 |
Unrealized gains (losses) on commodity risk management activities | -1 | 18 | -30 | 37 |
LIFO valuation adjustments | 20 | -22 | 34 | 16 |
Adjusted EBITDA related to discontinued operations | 0 | -23 | -27 | -63 |
Adjusted EBITDA related to unconsolidated affiliates | -170 | -158 | -366 | -323 |
Equity in earnings of unconsolidated affiliates | 57 | 37 | 136 | 109 |
Other, net | -15 | 5 | -18 | 8 |
Income from continuing operations before income tax expense | 609 | 493 | 1,222 | 898 |
Intrastate transportation and storage: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Segment Adjusted EBITDA: | 110 | 112 | 287 | 244 |
Interstate transportation and storage: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Segment Adjusted EBITDA: | 265 | 361 | 565 | 658 |
Midstream: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Segment Adjusted EBITDA: | 157 | 127 | 283 | 214 |
NGL transportation and services: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Segment Adjusted EBITDA: | 141 | 77 | 269 | 157 |
Investment in Sunoco Logistics: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Segment Adjusted EBITDA: | 280 | 244 | 488 | 480 |
Retail marketing: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Segment Adjusted EBITDA: | 136 | 97 | 245 | 134 |
All other: | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Segment Adjusted EBITDA: | $80 | $51 | $238 | $138 |
Reportable_Segments_Segment_As
Reportable Segments Segment Assets (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Segment Reporting Information [Line Items] | ' | ' |
Assets | $44,223 | $43,702 |
Intrastate transportation and storage: | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Assets | 4,504 | 4,606 |
Interstate transportation and storage: | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Assets | 10,158 | 10,988 |
Midstream: | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Assets | 3,307 | 3,133 |
NGL transportation and services: | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Assets | 4,576 | 4,326 |
Investment in Sunoco Logistics: | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Assets | 13,437 | 11,650 |
Retail marketing: | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Assets | 4,532 | 3,936 |
All other: | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Assets | $3,709 | $5,063 |