DEI_Document
DEI Document | 3 Months Ended | |
Mar. 31, 2015 | 1-May-15 | |
Entity Information [Line Items] | ||
Entity Registrant Name | Energy Transfer Equity, L.P. | |
Entity Central Index Key | 1276187 | |
Current Fiscal Year End Date | -28 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | 31-Mar-15 | |
Document Fiscal Year Focus | 2015 | |
Document Fiscal Period Focus | Q1 | |
Amendment Flag | FALSE | |
Entity Common Stock, Shares Outstanding | 539,234,023 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
ASSETS | ||
Cash and cash equivalents | $1,863 | $847 |
Accounts receivable, net | 2,863 | 3,378 |
Accounts receivable from related companies | 69 | 35 |
Inventories | 1,461 | 1,467 |
Exchanges receivable | 45 | 44 |
Price risk management assets | 77 | 81 |
Other current assets | 411 | 301 |
Total current assets | 6,789 | 6,153 |
PROPERTY, PLANT AND EQUIPMENT | 47,400 | 45,018 |
ACCUMULATED DEPRECIATION | -5,058 | -4,726 |
PROPERTY, PLANT AND EQUIPMENT, net | 42,342 | 40,292 |
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 3,656 | 3,659 |
NON-CURRENT PRICE RISK MANAGEMENT ASSETS | 9 | 10 |
GOODWILL | 7,702 | 7,865 |
INTANGIBLE ASSETS, net | 5,553 | 5,582 |
OTHER NON-CURRENT ASSETS, net | 953 | 908 |
Total assets | 67,004 | 64,469 |
LIABILITIES AND EQUITY | ||
Accounts payable | 2,865 | 3,349 |
Accounts payable to related companies | 12 | 19 |
Exchanges payable | 156 | 184 |
Price risk management liabilities | 17 | 21 |
Accrued and other current liabilities | 2,008 | 2,201 |
Current maturities of long-term debt | 269 | 1,008 |
Total current liabilities | 5,327 | 6,782 |
LONG-TERM DEBT, less current maturities | 33,158 | 29,653 |
DEFERRED INCOME TAXES | 4,139 | 4,325 |
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES | 228 | 154 |
OTHER NON-CURRENT LIABILITIES | 1,313 | 1,193 |
COMMITMENTS AND CONTINGENCIES | ||
PREFERRED UNITS OF SUBSIDIARY | 33 | 33 |
REDEEMABLE NONCONTROLLING INTEREST | 15 | 15 |
EQUITY: | ||
General Partner | -1 | -1 |
Limited Partners: | ||
Common Unitholders | 695 | 648 |
Class D Units | 18 | 22 |
Accumulated other comprehensive loss | -5 | -5 |
Total partners’ capital | 707 | 664 |
Noncontrolling interest | 22,084 | 21,650 |
Total equity | 22,791 | 22,314 |
Total liabilities and equity | $67,004 | $64,469 |
Consolidated_Statements_Of_Ope
Consolidated Statements Of Operations (USD $) | 3 Months Ended | |
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
REVENUES: | ||
Natural gas sales | $1,035 | $1,430 |
NGL sales | 981 | 1,254 |
Crude sales | 2,208 | 4,093 |
Gathering, transportation and other fees | 1,046 | 872 |
Refined product sales | 3,656 | 4,478 |
Other | 1,454 | 953 |
Total revenues | 10,380 | 13,080 |
COSTS AND EXPENSES: | ||
Cost of products sold | 8,487 | 11,442 |
Operating expenses | 628 | 424 |
Depreciation, depletion and amortization | 493 | 373 |
Selling, general and administrative | 155 | 131 |
Total costs and expenses | 9,763 | 12,370 |
OPERATING INCOME | 617 | 710 |
OTHER INCOME (EXPENSE): | ||
Interest expense, net of interest capitalized | -371 | -315 |
Equity in earnings of unconsolidated affiliates | 57 | 104 |
Losses on interest rate derivatives | -77 | -2 |
Gain on sale of AmeriGas common units | 0 | 70 |
Other, net | 7 | 2 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 233 | 569 |
Income tax expense from continuing operations | 12 | 145 |
INCOME FROM CONTINUING OPERATIONS | 221 | 424 |
Income from discontinued operations | 0 | 24 |
NET INCOME | 221 | 448 |
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST | -63 | 280 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 284 | 168 |
General Partner’s interest in net income | 1 | 0 |
Class D Unitholder’s interest in net income | 1 | 1 |
Limited Partners’ interest in net income | $282 | $167 |
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT: | ||
Basic | $0.52 | $0.30 |
Diluted | $0.52 | $0.30 |
NET INCOME PER LIMITED PARTNER UNIT: | ||
Basic | $0.52 | $0.30 |
Diluted | $0.52 | $0.30 |
Consolidated_Statements_Of_Com
Consolidated Statements Of Comprehensive Income (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Statement of Comprehensive Income [Abstract] | ||
Net income | $221 | $448 |
Other comprehensive income (loss), net of tax: | ||
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges | 0 | 4 |
Change in value of derivative instruments accounted for as cash flow hedges | 1 | -4 |
Change in value of available-for-sale securities | 1 | 0 |
Actuarial gain (loss) relating to pension and other postretirement benefits | 45 | -1 |
Foreign currency translation adjustments | -2 | -3 |
Change in other comprehensive income from unconsolidated affiliates | -2 | -7 |
Other comprehensive income (loss), net of tax | 43 | -11 |
Comprehensive income | 264 | 437 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | -20 | 272 |
Comprehensive income attributable to partners | $284 | $165 |
Consolidated_Statement_Of_Equi
Consolidated Statement Of Equity (USD $) | Total | General Partner | Common Unitholders | Class D Units | Accumulated Other Comprehensive Loss | Non- controlling Interest |
In Millions | ||||||
Balance, December 31, 2014 at Dec. 31, 2014 | $22,314 | ($1) | $648 | $22 | ($5) | $21,650 |
Distributions to partners | -244 | -1 | -242 | -1 | 0 | 0 |
Distributions to noncontrolling interest | -565 | 0 | 0 | 0 | 0 | -565 |
Subsidiary units issued for cash | 857 | 0 | 0 | 0 | 0 | 857 |
Conversion of Class D Units to ETE Common Units | 0 | 0 | 7 | -7 | 0 | 0 |
Non-cash compensation expense, net of units tendered by employees for tax withholdings | 16 | 0 | 1 | 3 | 0 | 12 |
Capital contributions received from noncontrolling interest | 219 | 0 | 0 | 0 | 0 | 219 |
Sale of noncontrolling interest in Rover Pipeline LLC to AE–Midco Rover, LLC | 64 | 0 | 0 | 0 | 0 | 64 |
Sunoco Logistics acquisition of noncontrolling interest | -129 | 0 | 0 | 0 | 0 | -129 |
Other comprehensive income, net of tax | 43 | 0 | 0 | 0 | 0 | 43 |
Other, net | -5 | 0 | -1 | 0 | 0 | -4 |
Net income (loss) | 221 | 1 | 282 | 1 | 0 | -63 |
Balance, March 31, 2015 at Mar. 31, 2015 | $22,791 | ($1) | $695 | $18 | ($5) | $22,084 |
Consolidated_Statements_Of_Cas
Consolidated Statements Of Cash Flows (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net income (loss) | $221 | $448 |
Reconciliation of net income to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 493 | 373 |
Deferred income taxes | 20 | -109 |
Amortization included in interest expense | -10 | -12 |
Non-cash compensation expense | 23 | 20 |
Gain on sale of AmeriGas common units | 0 | -70 |
Inventory valuation adjustments | 34 | -14 |
Equity in earnings of unconsolidated affiliates | -57 | -104 |
Distributions from unconsolidated affiliates | 64 | 67 |
Other non-cash | -9 | -16 |
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | -204 | 246 |
Net cash provided by operating activities | 575 | 829 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Cash paid for acquisitions, net of cash received | -370 | -214 |
Cash paid for acquisition of noncontrolling interest | -129 | 0 |
Cash proceeds from sale of noncontrolling interest in Rover Pipeline LLC to AE–Midco Rover, LLC | 64 | 0 |
Cash proceeds from the sale of AmeriGas common units | 0 | 381 |
Capital expenditures (excluding allowance for equity funds used during construction) | -2,158 | -942 |
Contributions in aid of construction costs | 4 | 7 |
Contributions to unconsolidated affiliates | 34 | 50 |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 33 | 27 |
Proceeds from the sale of assets | 9 | 11 |
Other | -4 | -21 |
Net cash used in investing activities | -2,585 | -801 |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Proceeds from borrowings | 8,731 | 3,170 |
Repayments of long-term debt | -5,938 | -1,977 |
Subsidiary equity offerings, net of issue costs | 857 | 175 |
Distributions to partners | -244 | -195 |
Debt issuance costs | -33 | -17 |
Distributions to noncontrolling interest | -565 | -397 |
Capital contributions received from noncontrolling interest | 219 | 0 |
Units repurchased under buyback program | 0 | -366 |
Other, net | -1 | -1 |
Net cash provided by financing activities | 3,026 | 392 |
INCREASE IN CASH AND CASH EQUIVALENTS | 1,016 | 420 |
CASH AND CASH EQUIVALENTS, beginning of period | 847 | 590 |
CASH AND CASH EQUIVALENTS, end of period | $1,863 | $1,010 |
Operations_And_Organization
Operations And Organization | 3 Months Ended | |
Mar. 31, 2015 | ||
Operations And Organization [Abstract] | ||
Operations And Organization | ORGANIZATION AND BASIS OF PRESENTATION: | |
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis. | ||
The consolidated financial statements of ETE presented herein include the results of operations of: | ||
• | the Parent Company; | |
• | our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”); | |
• | ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDRs in ETP and Regency; and | |
• | our wholly-owned subsidiary, Lake Charles LNG. | |
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein. | ||
Our activities are primarily conducted through our operating subsidiaries as follows: | ||
• | ETP is a publicly traded partnership whose operations are conducted through the following subsidiaries: | |
• | ETC OLP, a Texas limited partnership 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 its 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 its 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 Fayetteville Express Pipeline, LLC, 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 Pipeline, LLC, 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, LLC, a Delaware limited liability company engaged in natural gas compression services and related equipment sales. | |
• | ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle and Sunoco, Inc. operations are described as follows: | |
• | Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. In January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger. | |
• | Sunoco, Inc. owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, ETP combined certain Sunoco, Inc. retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and Sunoco, Inc. | |
• | Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets. | |
• | ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 44% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas, Louisiana, Maryland, Virginia, Tennessee, Georgia and Hawaii and other commercial customers. | |
• | Regency is a master limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; natural gas and NGL marketing and trading, and the management of coal and natural resource properties in the United States. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Regency also holds a 30% interest in Lone Star. | |
• | Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC. | |
Our financial statements reflect the following reportable business segments: | ||
• | Investment in ETP, including the consolidated operations of ETP. | |
• | Investment in Regency, including the consolidated operations of Regency. | |
• | Investment in Lake Charles LNG, including the operations of Lake Charles LNG. | |
• | Corporate and Other, including the following: | |
• | activities of the Parent Company; and | |
• | the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. | |
The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. | ||
The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates. | ||
Certain prior period amounts have been reclassified to conform to the 2015 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 ETP’s retail marketing operations, 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 ETP’s retail marketing operations were $736 million and $530 million for the three months ended March 31, 2015 and 2014, respectively. | ||
New Accounting Pronouncement | ||
In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810) (“ASU 2015-02”), which changed the requirements for consolidations analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2016, and we are currently evaluating the impact that it will have on our consolidated financial statements and related disclosures. |
Acquisitions
Acquisitions | 3 Months Ended |
Mar. 31, 2015 | |
ACQUISITIONS AND DIVESTITURE [Abstract] | |
Acquisitions | ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: |
2015 Transactions | |
Regency Merger | |
In April 2015, ETP and Regency completed the previously announced merger of an indirect subsidiary of ETP, with and into Regency, with Regency surviving the merger as a wholly-owned subsidiary of ETP (the “Regency Merger”). As part of the merger consideration, each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP Common Units. Based on the Regency units outstanding, ETP issued approximately 172.2 million ETP Common Units to Regency unitholders, including approximately 15.5 million units issued to ETP subsidiaries. The approximately 1.9 million outstanding Regency Series A Preferred Units were converted into corresponding new ETP Series A Preferred Units. | |
In connection with the transaction, ETE, which owns the general partner and 100% of the incentive distribution rights of ETP, will reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy will be $80 million in the first year post-closing and $60 million per year for the following four years. | |
Dropdown of Sunoco, LLC Interests | |
In April 2015, Sunoco LP completed the acquisition of a 31.58% equity interest in Sunoco, LLC from Retail Holdings. Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. The transaction was valued at approximately $816 million. Sunoco LP paid $775 million in cash and issued $41 million of Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015. | |
Bakken Pipeline Transaction | |
In March 2015, ETE transferred 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. The IDR subsidies from ETE to ETP, including the impact from distributions on ETP Class I Units, will be reduced by $55 million in 2015 and $30 million in 2016. | |
Discontinued Operations | |
Discontinued operations for the three months ended March 31, 2014 included the results of operations for a marketing business that had been recently acquired and was sold effective April 1, 2014. |
Advances_to_and_Investments_in
Advances to and Investments in Unconsolidated Affiliates | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
INVESTMENTS IN UNCONSOLIDATED AFFILIATES [Abstract] | ||||||||
Advances to and Investments in Unconsolidated Advances to Affiliates | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: | |||||||
The following investments in unconsolidated affiliates are reflected in our consolidated financial statements using the equity method: | ||||||||
• | AmeriGas. In January 2014, ETP recognized a gain on the sale of 9.2 million AmeriGas common units that were originally received in connection with the contribution of ETP’s propane business to AmeriGas in 2012. As of March 31, 2015, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company. | |||||||
• | Citrus. ETP owns a 50% interest in Citrus, which owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. | |||||||
• | FEP. ETP owns a 50% interest in the FEP, which owns a natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company, LLC in Panola County, Mississippi. | |||||||
• | HPC. Regency owns a 49.99% interest in HPC, which, through its ownership of the Regency Intrastate Gas System, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through an intrastate pipeline system. | |||||||
• | MEP. Regency owns a 50% interest in MEP, which owns natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. | |||||||
The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented). | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Revenue | $ | 1,428 | $ | 1,819 | ||||
Operating income | 553 | 464 | ||||||
Net income | 437 | 344 | ||||||
In addition to the equity method investments described above, our subsidiaries have other equity method investments, which are not significant to our consolidated financial statements. |
Cash_And_Cash_Equivalents
Cash And Cash Equivalents | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Supplemental Cash Flow Information [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. | ||||||||
Non-cash investing and financing activities were as follows: | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
NON-CASH INVESTING ACTIVITIES: | ||||||||
Accrued capital expenditures | $ | 658 | $ | 192 | ||||
Net gains from subsidiary common unit issuances | $ | — | $ | 603 | ||||
NON-CASH FINANCING ACTIVITIES: | ||||||||
Subsidiary issuances of common units in connection with acquisitions | $ | — | $ | 4,015 | ||||
Long-term debt assumed in PVR Acquisition | $ | — | $ | 1,887 | ||||
Inventories_Notes
Inventories (Notes) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Inventory, Net [Abstract] | ||||||||
Inventories | INVENTORIES: | |||||||
Inventories consisted of the following: | ||||||||
March 31, | December 31, | |||||||
2015 | 2014 | |||||||
Natural gas and NGLs | $ | 294 | $ | 392 | ||||
Crude oil | 470 | 364 | ||||||
Refined products | 367 | 392 | ||||||
Other | 330 | 319 | ||||||
Total inventories | $ | 1,461 | $ | 1,467 | ||||
Fair_Value_Measurements
Fair Value Measurements | 3 Months Ended | |||||||||||||||
Mar. 31, 2015 | ||||||||||||||||
Fair Value Measurements [Abstract] | ||||||||||||||||
Fair Value Measurements | FAIR VALUE MEASUREMENTS: | |||||||||||||||
We have commodity derivatives, interest rate derivatives and embedded derivatives in the Regency Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of 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, and we discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the three months ended March 31, 2015, no transfers were made between any levels within the fair value hierarchy. | ||||||||||||||||
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of March 31, 2015 and December 31, 2014 was $35.15 billion and $31.68 billion, respectively. As of March 31, 2015 and December 31, 2014, the aggregate carrying amount of our consolidated debt obligations was $33.43 billion and $30.66 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 March 31, 2015 and December 31, 2014 based on inputs used to derive their fair values: | ||||||||||||||||
Fair Value Measurements at | ||||||||||||||||
31-Mar-15 | ||||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Total | ||||||||||||||||
Assets: | ||||||||||||||||
Interest rate derivatives | $ | 6 | $ | — | $ | 6 | $ | — | ||||||||
Commodity derivatives: | ||||||||||||||||
Condensate — Forward Swaps | 35 | — | 35 | — | ||||||||||||
Natural Gas: | ||||||||||||||||
Basis Swaps IFERC/NYMEX | 11 | 11 | — | — | ||||||||||||
Swing Swaps IFERC | 2 | — | 2 | — | ||||||||||||
Fixed Swaps/Futures | 317 | 295 | 22 | — | ||||||||||||
Forward Physical Swaps | 1 | — | 1 | — | ||||||||||||
Natural Gas Liquids — Forwards/Swaps | 42 | 25 | 17 | — | ||||||||||||
Power: | ||||||||||||||||
Forwards | 5 | — | 5 | — | ||||||||||||
Futures | 4 | 4 | — | — | ||||||||||||
Options — Calls | 2 | 2 | — | — | ||||||||||||
Refined Products — Futures | 7 | 7 | — | — | ||||||||||||
Crude – Futures | 2 | 2 | — | — | ||||||||||||
Total commodity derivatives | 428 | 346 | 82 | — | ||||||||||||
Total assets | $ | 434 | $ | 346 | $ | 88 | $ | — | ||||||||
Liabilities: | ||||||||||||||||
Interest rate derivatives | $ | (226 | ) | $ | — | $ | (226 | ) | $ | — | ||||||
Embedded derivatives in the Regency Preferred Units | (14 | ) | — | — | (14 | ) | ||||||||||
Commodity derivatives: | ||||||||||||||||
Condensate — Forward Swaps | (1 | ) | — | (1 | ) | — | ||||||||||
Natural Gas: | ||||||||||||||||
Basis Swaps IFERC/NYMEX | (10 | ) | (10 | ) | — | — | ||||||||||
Swing Swaps IFERC | (4 | ) | (1 | ) | (3 | ) | — | |||||||||
Fixed Swaps/Futures | (293 | ) | (293 | ) | — | — | ||||||||||
Natural Gas Liquids — Forwards/Swaps | (22 | ) | (22 | ) | — | — | ||||||||||
Power: | ||||||||||||||||
Forwards | (4 | ) | — | (4 | ) | — | ||||||||||
Futures | (3 | ) | (3 | ) | — | — | ||||||||||
Options — Puts | (4 | ) | (4 | ) | — | — | ||||||||||
Refined Products — Futures | (5 | ) | (5 | ) | — | — | ||||||||||
Crude — Futures | (3 | ) | (3 | ) | — | — | ||||||||||
Total commodity derivatives | (349 | ) | (341 | ) | (8 | ) | — | |||||||||
Total liabilities | $ | (589 | ) | $ | (341 | ) | $ | (234 | ) | $ | (14 | ) | ||||
Fair Value Measurements at | ||||||||||||||||
31-Dec-14 | ||||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Total | ||||||||||||||||
Assets: | ||||||||||||||||
Interest rate derivatives | $ | 3 | $ | — | $ | 3 | $ | — | ||||||||
Commodity derivatives: | ||||||||||||||||
Condensate — Forward Swaps | 36 | — | 36 | — | ||||||||||||
Natural Gas: | ||||||||||||||||
Basis Swaps IFERC/NYMEX | 19 | 19 | — | — | ||||||||||||
Swing Swaps IFERC | 26 | 1 | 25 | — | ||||||||||||
Fixed Swaps/Futures | 566 | 541 | 25 | — | ||||||||||||
Forward Physical Contracts | 1 | — | 1 | — | ||||||||||||
Power: | ||||||||||||||||
Forwards | 3 | — | 3 | — | ||||||||||||
Futures | 4 | 4 | — | — | ||||||||||||
Natural Gas Liquids — Forwards/Swaps | 69 | 46 | 23 | — | ||||||||||||
Refined Products — Futures | 21 | 21 | — | — | ||||||||||||
Total commodity derivatives | 745 | 632 | 113 | — | ||||||||||||
Total assets | $ | 748 | $ | 632 | $ | 116 | $ | — | ||||||||
Liabilities: | ||||||||||||||||
Interest rate derivatives | $ | (155 | ) | $ | — | $ | (155 | ) | $ | — | ||||||
Embedded derivatives in the Regency Preferred Units | (16 | ) | — | — | (16 | ) | ||||||||||
Natural Gas: | ||||||||||||||||
Basis Swaps IFERC/NYMEX | (18 | ) | (18 | ) | — | — | ||||||||||
Swing Swaps IFERC | (25 | ) | (2 | ) | (23 | ) | — | |||||||||
Fixed Swaps/Futures | (490 | ) | (490 | ) | — | — | ||||||||||
Power: | ||||||||||||||||
Forwards | (4 | ) | — | (4 | ) | — | ||||||||||
Futures | (2 | ) | (2 | ) | — | — | ||||||||||
Natural Gas Liquids — Forwards/Swaps | (32 | ) | (32 | ) | — | — | ||||||||||
Refined Products — Futures | (7 | ) | (7 | ) | — | — | ||||||||||
Total commodity derivatives | (578 | ) | (551 | ) | (27 | ) | — | |||||||||
Total liabilities | $ | (749 | ) | $ | (551 | ) | $ | (182 | ) | $ | (16 | ) | ||||
The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the three months ended March 31, 2015. | ||||||||||||||||
Balance, December 31, 2014 | $ | (16 | ) | |||||||||||||
Net unrealized gains included in other income (expense) | 2 | |||||||||||||||
Balance, March 31, 2015 | $ | (14 | ) |
Net_Income_per_Limited_Partner
Net Income per Limited Partner Unit | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Earnings Per Share [Abstract] | ||||||||
Net Income Per Limited Partner Unit | NET INCOME PER LIMITED PARTNER UNIT: | |||||||
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 | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Income from continuing operations | $ | 221 | $ | 424 | ||||
Less: Income from continuing operations attributable to noncontrolling interest | (63 | ) | 259 | |||||
Income from continuing operations, net of noncontrolling interest | 284 | 165 | ||||||
Less: General Partner’s interest in income from continuing operations | 1 | — | ||||||
Less: Class D Unitholder’s interest in income from continuing operations | 1 | 1 | ||||||
Income from continuing operations available to Limited Partners | $ | 282 | $ | 164 | ||||
Basic Income from Continuing Operations per Limited Partner Unit: | ||||||||
Weighted average limited partner units | 538.8 | 557.7 | ||||||
Basic income from continuing operations per Limited Partner unit | $ | 0.52 | $ | 0.3 | ||||
Basic income from discontinued operations per Limited Partner unit | $ | 0 | $ | 0 | ||||
Diluted Income from Continuing Operations per Limited Partner Unit: | ||||||||
Income from continuing operations available to Limited Partners | $ | 282 | $ | 164 | ||||
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder | (1 | ) | (1 | ) | ||||
Diluted income from continuing operations available to Limited Partners | $ | 281 | $ | 163 | ||||
Weighted average limited partner units | 538.8 | 557.7 | ||||||
Dilutive effect of unconverted unit awards | 0.7 | 0.7 | ||||||
Weighted average limited partner units, assuming dilutive effect of unvested unit awards | 539.5 | 558.4 | ||||||
Diluted income from continuing operations per Limited Partner unit | $ | 0.52 | $ | 0.3 | ||||
Diluted income from discontinued operations per Limited Partner unit | $ | 0 | $ | 0 | ||||
Debt_Obligations
Debt Obligations | 3 Months Ended |
Mar. 31, 2015 | |
Debt Obligations [Abstract] | |
Debt Obligations | DEBT OBLIGATIONS: |
Parent Company Indebtedness | |
The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets. | |
ETE Term Loan Facility | |
In March 2015, the Parent Company entered into a Senior Secured Term Loan C Agreement (the “ETE Term Loan C Agreement” and, together with the Parent Company’s other term loan agreements, the “ETE Term Loan Facility”), which increased the aggregate principal amount under the ETE Term Loan Facility to $2.25 billion, an increase of $850 million. The Parent Company used the proceeds (i) to fund the cash consideration for the Bakken Pipeline Transaction, (ii) to repay amounts outstanding under the Partnership’s revolving credit facility, and (iii) to pay transaction fees and expenses related to the Bakken Pipeline Transaction, the Term Loan Facility and other transactions incidental thereto. Under the ETE Term Loan C Agreement, interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the Parent Company for each interest period. The applicable margin for LIBOR rate loans is 3.25% and the applicable margin for base rate loans is 2.25%. | |
Revolving Credit Facility | |
The Parent Company’s revolving credit facility has a capacity of $1.5 billion. As of March 31, 2015, there were $925 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $575 million. | |
Senior Notes | |
The Parent Company currently has outstanding an aggregate of $1.19 billion in principal amount of 7.5% senior notes due 2020 and $1.15 billion in principal amount of 5.875% senior notes due 2024. | |
Subsidiary Indebtedness | |
ETP Senior Notes | |
In March 2015, ETP issued $1.0 billion aggregate principal amount of 4.05% senior notes due March 2025, $500 million aggregate principal amount of 4.90% senior notes due March 2035, and $1.0 billion aggregate principal amount of 5.15% senior notes due March 2045. ETP used the $2.48 billion net proceeds from the offering to pay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes. | |
Sunoco LP Senior Notes | |
In April 2015, Sunoco LP issued $800 million aggregate principal amount of 6.375% senior notes due April 2023. The net proceeds from the offering were used to fund the cash portion of the dropdown of Sunoco, LLC interests. | |
Subsidiary Credit Facilities | |
ETP Credit Facility | |
The ETP Credit Facility allows for borrowings of up to $3.75 billion and expires in November 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of ETP’s current and future unsecured debt. As of March 31, 2015, the ETP Credit Facility had no outstanding borrowings. | |
On April 30, 2015, ETP borrowed $1.5 billion under the ETP Credit Facility to partially fund the repayment of the Regency Credit Facility. | |
Regency Credit Facility | |
The Regency Credit Facility allowed for borrowings of $2.5 billion and would have expired on November 25, 2019. As of March 31, 2015, the Regency Credit Facility had a balance outstanding of $2.09 billion in outstanding borrowings and approximately $16 million in letters of credit. On April 30, 2015, in connection with the Regency Merger, the Regency Credit Facility was paid off in full and terminated. | |
Sunoco Logistics Credit Facilities | |
In March 2015, Sunoco Logistics amended and restated its $1.5 billion unsecured credit facility, which was scheduled to mature in November 2018. The amended and restated credit facility is a $2.5 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions. As of March 31, 2015, the Sunoco Logistics Credit Facility had $350 million of outstanding borrowings. | |
Sunoco LP Credit Facility | |
Sunoco LP maintains a $1.25 billion revolving credit facility (the “Sunoco LP Credit Facility”), which expires in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million. As of March 31, 2015, the Sunoco LP Credit Facility had $685 million of outstanding borrowings. | |
In April 2015, Sunoco LP amended the Sunoco LP Credit Facility to allow for borrowings of up to $1.5 billion. | |
Compliance with Our Covenants | |
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of March 31, 2015. |
Redeemable_Noncontrolling_Inte
Redeemable Noncontrolling Interest (Notes) | 3 Months Ended |
Mar. 31, 2015 | |
Redeemable Noncontrolling Interest [Table Text Block] | REDEEMABLE NONCONTROLLING INTERESTS: |
The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheets. |
Equity
Equity | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Partners' Capital Notes [Abstract] | |||||||||
Equity | |||||||||
EQUITY: | |||||||||
ETE Common Unit Activity | |||||||||
The change in ETE Common Units during the three months ended March 31, 2015 was as follows: | |||||||||
Number of | |||||||||
Units | |||||||||
Outstanding at December 31, 2014 | 538.8 | ||||||||
Conversion of Class D Units to ETE Common Units | 0.5 | ||||||||
Outstanding at March 31, 2015 | 539.3 | ||||||||
Sales of Common Units by Subsidiaries | |||||||||
The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Regency and the underlying book value arising from the issuance or redemption of units by ETP or Regency (excluding transactions with the Parent Company) as capital transactions. | |||||||||
Sales of Common Units by ETP | |||||||||
During the three months ended March 31, 2015, ETP received proceeds of $76 million, net of commissions of $1 million, from the issuance of units pursuant to equity distribution agreements, which were used for general partnership purposes. As of March 31, 2015, approximately $1.33 billion of ETP Common Units remained available to be issued under an equity distribution agreement. | |||||||||
During the three months ended March 31, 2015, distributions of $59 million were reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of 1.0 million ETP Common Units. As of March 31, 2015, a total of 6.3 million ETP Common Units remain available to be issued under the existing registration statement. | |||||||||
ETP Class H and Class I Units | |||||||||
In March 2015, ETE transferred 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics. In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. The IDR subsidies from ETE to ETP, including the impact from distributions on ETP Class I Units, will be reduced by $55 million in 2015 and $30 million in 2016. | |||||||||
The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “ETP Quarterly Distributions of Available Cash.” | |||||||||
Sales of Common Units by Regency | |||||||||
In January 2015, Regency entered into an equity distribution agreement with another group of banks and investment companies under which Regency may offer and sell common units for an aggregate offering price of up to $1 billion. | |||||||||
For the three months ended March 31, 2015, Regency received proceeds of $34 million from units issued pursuant to its equity distribution agreements, which proceeds were used for general partnership purposes. Regency did not issue any common units under the distribution agreement subsequent to March 31, 2015, and the equity distribution agreement terminated as a result of the merger with ETP in April 2015. | |||||||||
Sales of Common Units by Sunoco Logistics | |||||||||
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. During the three months ended March 31, 2015, Sunoco Logistics received proceeds of $142 million, net of commissions of $1 million, which were used for general partnership purposes. | |||||||||
Additionally, Sunoco Logistics completed a public offering of 13.5 million common units for net proceeds of $547 million in March 2015. The net proceeds from this offering were used to repay outstanding borrowings under the $2.5 billion Sunoco Logistics Credit Facility and for general partnership purposes. In April 2015, an additional 2.0 million common units were issued for net proceeds of $82 million related to the exercise of an option in connection with the March 2015 offering. | |||||||||
Parent Company Quarterly Distributions of Available Cash | |||||||||
Following are distributions declared and/or paid by us subsequent to December 31, 2014: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
December 31, 2014 | February 6, 2015 | February 19, 2015 | $ | 0.45 | |||||
March 31, 2015 | 8-May-15 | 19-May-15 | 0.49 | ||||||
ETP Quarterly Distributions of Available Cash | |||||||||
Following are distributions declared and/or paid by ETP subsequent to December 31, 2014: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
31-Dec-14 | February 6, 2015 | February 13, 2015 | $ | 0.995 | |||||
March 31, 2015 | 8-May-15 | 15-May-15 | 1.015 | ||||||
In connection with previous transactions, including the Regency Merger, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on ETP Class I Units. | |||||||||
Total Year | |||||||||
2015 (remainder) | $ | 84 | |||||||
2016 | 137 | ||||||||
2017 | 145 | ||||||||
2018 | 140 | ||||||||
2019 | 130 | ||||||||
2020 | 35 | ||||||||
2021 | 35 | ||||||||
2022 | 35 | ||||||||
2023 | 35 | ||||||||
2024 | 18 | ||||||||
Regency Quarterly Distributions of Available Cash | |||||||||
Following are distributions declared and/or paid by Regency subsequent to December 31, 2014: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
31-Dec-14 | February 6, 2015 | February 13, 2015 | $ | 0.5025 | |||||
ETP’s acquisition of Regency closed on April 30, 2015; therefore, no distributions in relation to the quarter ended March 31, 2015 will be paid by Regency. | |||||||||
Sunoco Logistics Quarterly Distributions of Available Cash | |||||||||
Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2014: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
31-Dec-14 | 9-Feb-15 | 13-Feb-15 | $ | 0.4 | |||||
31-Mar-15 | 11-May-15 | 15-May-15 | 0.419 | ||||||
Sunoco LP Quarterly Distributions of Available Cash | |||||||||
Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2014: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
31-Dec-14 | February 17, 2015 | February 27, 2015 | $ | 0.6 | |||||
31-Mar-15 | 19-May-15 | 29-May-15 | 0.645 | ||||||
Accumulated Other Comprehensive Income (Loss) | |||||||||
The following table presents the components of AOCI, net of tax: | |||||||||
March 31, | December 31, 2014 | ||||||||
2015 | |||||||||
Available-for-sale securities | $ | 4 | $ | 3 | |||||
Foreign currency translation adjustment | (5 | ) | (3 | ) | |||||
Net loss on commodity related hedges | — | (1 | ) | ||||||
Actuarial loss related to pensions and other postretirement benefits | (12 | ) | (57 | ) | |||||
Investments in unconsolidated affiliates, net | — | 2 | |||||||
Subtotal | (13 | ) | (56 | ) | |||||
Amounts attributable to noncontrolling interest | 8 | 51 | |||||||
Total AOCI, net of tax | $ | (5 | ) | $ | (5 | ) |
Income_Taxes_Notes
Income Taxes (Notes) | 3 Months Ended |
Mar. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | INCOME TAXES: |
For the three months ended March 31, 2015, the Partnership’s income tax expense from continuing operations included favorable state income tax adjustments of $14 million. For the three months ended March 31, 2014, the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $85 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes. | |
During the three months ended March 31, 2015, Sunoco received a notice of disallowance denying previously filed refund claims related to certain government incentive payments. However, Sunoco intends to file a refund suit with the United States Court of Federal Claims or the United States District Court having jurisdiction. In preparation for filing its complaint to the Court, Sunoco formalized its claims by filing amended Federal income tax returns with the Internal Revenue Service on March 10, 2015. The amended returns include an increase in the claims of $92 million, bringing the total claimed amount to $464 million. This increase relates primarily to the inclusion of certain tax years that were previously regarded as closed for purposes of calculating the potential refund. Consistent with prior treatment, Sunoco has established a reserve for the full amount of the increase due to the uncertain nature of the claims. |
Regulatory_Matters_Commitments
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | ||||||||
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: | |||||||
Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus | ||||||||
Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011. | ||||||||
On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011. | ||||||||
FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs. | ||||||||
Contingent Residual Support Agreement — AmeriGas | ||||||||
In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchases. | ||||||||
Panhandle Holdings Guarantee of Collection | ||||||||
Panhandle guarantees the collections of the payment of $600 million of Regency 4.50% senior notes due 2023. | ||||||||
NGL Pipeline Regulation | ||||||||
ETP has interests in NGL pipelines located in Texas and New Mexico. ETP 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 ETP’s 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 ETP’s business, revenues and cash flow. | ||||||||
Transwestern Rate Case | ||||||||
On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to a 2011 settlement agreement with its shippers. On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in August 2015. | ||||||||
FGT Rate Case | ||||||||
On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015. | ||||||||
Commitments | ||||||||
In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations. | ||||||||
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Rental expense(1) | $ | 52 | $ | 32 | ||||
Less: Sublease rental income | (8 | ) | (8 | ) | ||||
Rental expense, net | $ | 44 | $ | 24 | ||||
(1) | Includes contingent rentals totaling $4 million and $3 million for the three months ended March 31, 2015 and 2014, respectively. | |||||||
Certain of our subsidiaries’ joint venture agreements require that they fund their proportionate shares of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. | ||||||||
Litigation and Contingencies | ||||||||
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. | ||||||||
MTBE Litigation | ||||||||
Sunoco, Inc., along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees. | ||||||||
As of March 31, 2015, Sunoco, Inc. is a defendant in five cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico and Pennsylvania cases assert natural resource damage claims. | ||||||||
Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability of Sunoco, Inc. in these matters. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position. | ||||||||
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation | ||||||||
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise approximately $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise has filed a notice of appeal. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed. | ||||||||
Other Litigation and Contingencies | ||||||||
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of March 31, 2015 and December 31, 2014, accruals of approximately $39 million and $37 million, respectively, were reflected on our 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 March 31, 2015 or December 31, 2014 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. | ||||||||
Attorney General of the Commonwealth of Massachusetts v. New England Gas Company. | ||||||||
On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses. | ||||||||
Environmental Matters | ||||||||
Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. | ||||||||
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position. | ||||||||
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs. | ||||||||
Environmental Remediation | ||||||||
Our subsidiaries are responsible for environmental remediation at certain sites, including the following: | ||||||||
• | Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. | |||||||
• | Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. | |||||||
• | Currently operating Sunoco, Inc. retail sites. | |||||||
• | Legacy sites related to Sunoco, Inc., that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites. | |||||||
• | Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of March 31, 2015, Sunoco, Inc. had been named as a PRP at approximately 51 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. | |||||||
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken 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. | ||||||||
March 31, | 31-Dec-14 | |||||||
2015 | ||||||||
Current | $ | 48 | $ | 41 | ||||
Non-current | 340 | 360 | ||||||
Total environmental liabilities | $ | 388 | $ | 401 | ||||
In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. | ||||||||
During the three months ended March 31, 2015 and 2014, the Partnership recorded $7 million and $8 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 | 3 Months Ended | ||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||
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, our subsidiaries 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. Following is a description of price risk management activities by operating entity. | |||||||||||||||||||
ETP | |||||||||||||||||||
ETP injects and holds natural gas in its 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). ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks 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 ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses 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 ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of ETP’s 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, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas. | |||||||||||||||||||
ETP is also exposed to market risk on natural gas it retains for fees in ETP’s intrastate transportation and storage segment and operational gas sales on ETP’s interstate transportation and storage segment. ETP uses 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. | |||||||||||||||||||
ETP is also exposed to commodity price risk on NGLs and residue gas it retains for fees in ETP’s midstream segment whereby ETP’s 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. ETP uses 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. | |||||||||||||||||||
ETP may use derivatives in ETP’s liquids transportation and services segment to manage ETP’s storage facilities and the purchase and sale of purity NGLs. | |||||||||||||||||||
Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products, crude and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Sunoco Logistics does not designate any of its derivative contracts as hedges for accounting purposes. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period. | |||||||||||||||||||
ETP also uses derivatives to hedge a variety of price risks in its retail marketing operations. Futures and swaps are used to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs. The derivatives used in ETP’s retail marketing operations represent economic hedges; however, ETP has elected not to designate any of these derivative contracts as hedges in these operations. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period. | |||||||||||||||||||
ETP’s trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to ETP’s transportation and storage segment’s operations and are netted in cost of products sold in the consolidated statements of operations. Additionally, ETP also has trading and marketing activities related to power and natural gas in its other operations which are also netted in cost of products sold. As a result of ETP’s trading activities and the use of derivative financial instruments in ETP’s transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attempts to manage this volatility through the use of daily position and profit and loss reports provided to ETP’s risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in ETP’s commodity risk management policy. | |||||||||||||||||||
The following table details ETP’s outstanding commodity-related derivatives: | |||||||||||||||||||
March 31, 2015 | December 31, 2014 | ||||||||||||||||||
Notional | Maturity | Notional | Maturity | ||||||||||||||||
Volume | Volume | ||||||||||||||||||
Mark-to-Market Derivatives | |||||||||||||||||||
(Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Fixed Swaps/Futures | 775,000 | 2015 | (232,500 | ) | 2015 | ||||||||||||||
Basis Swaps IFERC/NYMEX (1) | 3,842,500 | 2015-2016 | (13,907,500 | ) | 2015-2016 | ||||||||||||||
Options – Calls | 5,000,000 | 2015 | 5,000,000 | 2015 | |||||||||||||||
Power (Megawatt): | |||||||||||||||||||
Forwards | 225,131 | 2015 | 288,775 | 2015 | |||||||||||||||
Futures | 168,992 | 2015 | (156,000 | ) | 2015 | ||||||||||||||
Options — Puts | (177,942 | ) | 2015 | (72,000 | ) | 2015 | |||||||||||||
Options — Calls | 1,742,117 | 2015 | 198,556 | 2015 | |||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | 13,292,500 | 2015-2016 | 57,500 | 2015 | |||||||||||||||
Swing Swaps IFERC | 51,465,000 | 2015-2016 | 46,150,000 | 2015 | |||||||||||||||
Fixed Swaps/Futures | 1,705,000 | 2015-2016 | (8,779,000 | ) | 2015-2016 | ||||||||||||||
Forward Physical Contracts | 23,903,779 | 2015 | (9,116,777 | ) | 2015 | ||||||||||||||
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps | (768,100 | ) | 2015-2016 | (2,179,400 | ) | 2015 | |||||||||||||
Refined Products (Bbls) — Futures | (1,019,000 | ) | 2015 | 13,745,755 | 2015 | ||||||||||||||
Fair Value Hedging Derivatives | |||||||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | (23,295,000 | ) | 2016 | (39,287,500 | ) | 2015 | |||||||||||||
Fixed Swaps/Futures | (23,475,000 | ) | 2016 | (39,287,500 | ) | 2015 | |||||||||||||
Hedged Item — Inventory | 23,475,000 | 2016 | 39,287,500 | 2015 | |||||||||||||||
(1) | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. | ||||||||||||||||||
Regency | |||||||||||||||||||
Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. | |||||||||||||||||||
Commodity Derivative Instruments - Marketing & Trading. Regency conducts natural gas marketing and trading activities through its Logistics and Trading subsidiary. Regency engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. Regency’s activities are governed by its risk policy. As part of its natural gas marketing and trading activities, Regency enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales. Through Regency’s natural gas marketing activity, Regency will have credit exposure to additional counterparties. Regency minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, Regency’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, Regency nets the open positions of each counterparty. | |||||||||||||||||||
The following table details Regency’s outstanding commodity-related derivatives: | |||||||||||||||||||
March 31, 2015 | December 31, 2014 | ||||||||||||||||||
Notional | Maturity | Notional | Maturity | ||||||||||||||||
Volume | Volume | ||||||||||||||||||
Mark-to-Market Derivatives | |||||||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu) — Fixed Swaps/Futures | (17,875,000 | ) | 2015 | (25,525,000 | ) | 2015 | |||||||||||||
Propane (Gallons) — Forwards/Swaps | (21,966,000 | ) | 2015 | (29,148,000 | ) | 2015 | |||||||||||||
NGLs (Barrels) — Forwards/Swaps | (220,000 | ) | 2015 | (292,000 | ) | 2015 | |||||||||||||
WTI Crude Oil (Barrels) — Forwards/Swaps | (1,060,000 | ) | 2015-2016 | (1,252,000 | ) | 2015-2016 | |||||||||||||
Regency had swap contracts settled against certain NGLs, condensate and natural gas market prices. In April 2015, Regency terminated all outstanding swap contracts and received net proceeds of $56 million. | |||||||||||||||||||
Interest Rate Risk | |||||||||||||||||||
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and floating rate debt. We also manage our interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and floating rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. | |||||||||||||||||||
The following table summarizes our interest rate swaps outstanding none of which were designated as hedges for accounting purposes: | |||||||||||||||||||
Notional Amount | |||||||||||||||||||
Outstanding | |||||||||||||||||||
Entity | Term | Type(1) | March 31, | December 31, 2014 | |||||||||||||||
2015 | |||||||||||||||||||
ETP | July 2015(2) | Forward-starting to pay a fixed rate of 3.40% and receive a floating rate | $ | 100 | $ | 200 | |||||||||||||
ETP | July 2016(3) | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | 200 | 200 | |||||||||||||||
ETP | July 2017(4) | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | 300 | 300 | |||||||||||||||
ETP | July 2018(4) | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | 200 | 200 | |||||||||||||||
ETP | July 2019(4) | Forward-starting to pay a fixed rate of 3.01% and receive a floating rate | 500 | 300 | |||||||||||||||
ETP | Mar-19 | Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53% | 600 | — | |||||||||||||||
ETP | Feb-23 | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | — | 200 | |||||||||||||||
(1) | Floating rates are based on 3-month LIBOR. | ||||||||||||||||||
(2) | Represents the effective date. These forward starting swaps have a term 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 a term 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 ETP’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, ETP may at times require collateral under certain circumstances to mitigate credit risk as necessary. ETP also implements 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, ETP utilizes master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. | |||||||||||||||||||
ETP’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. ETP’s overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that could impact its 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. | |||||||||||||||||||
ETP has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to ETP on or about the settlement date for non-exchange traded derivatives, and ETP exchanges 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. | |||||||||||||||||||
Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of March 31, 2015 would be $72 million, which would be reduced by $1 million, due to the netting features. Regency has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets for it derivate contracts outside of its marketing and trading operations. | |||||||||||||||||||
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 | ||||||||||||||||||
March 31, 2015 | December 31, 2014 | March 31, 2015 | December 31, 2014 | ||||||||||||||||
Derivatives designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives (margin deposits) | $ | 3 | $ | 43 | $ | — | $ | — | |||||||||||
3 | 43 | — | — | ||||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives (margin deposits) | $ | 347 | $ | 617 | $ | (346 | ) | $ | (577 | ) | |||||||||
Commodity derivatives | 94 | 107 | (19 | ) | (23 | ) | |||||||||||||
Interest rate derivatives | 6 | 3 | (226 | ) | (155 | ) | |||||||||||||
Embedded derivatives in Regency Preferred Units | — | — | (14 | ) | (16 | ) | |||||||||||||
447 | 727 | (605 | ) | (771 | ) | ||||||||||||||
Total derivatives | $ | 450 | $ | 770 | $ | (605 | ) | $ | (771 | ) | |||||||||
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: | |||||||||||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||||||||||
Balance Sheet Location | March 31, 2015 | December 31, 2014 | March 31, 2015 | December 31, 2014 | |||||||||||||||
Derivatives in offsetting agreements: | |||||||||||||||||||
OTC contracts | Price risk management asset (liability) | $ | 20 | $ | 23 | $ | (18 | ) | $ | (23 | ) | ||||||||
Broker cleared derivative contracts | Other current assets | 334 | 674 | (356 | ) | (574 | ) | ||||||||||||
354 | 697 | (374 | ) | (597 | ) | ||||||||||||||
Offsetting agreements: | |||||||||||||||||||
Counterparty netting | Price risk management asset (liability) | (14 | ) | (19 | ) | 14 | 19 | ||||||||||||
Payments on margin deposit | Other current assets | 30 | 5 | (4 | ) | (22 | ) | ||||||||||||
16 | (14 | ) | 10 | (3 | ) | ||||||||||||||
Net derivatives with offsetting agreements | 370 | 683 | (364 | ) | (600 | ) | |||||||||||||
Derivatives without offsetting agreements | 80 | 87 | (241 | ) | (171 | ) | |||||||||||||
Total derivatives | $ | 450 | $ | 770 | $ | (605 | ) | $ | (771 | ) | |||||||||
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 | |||||||||||||||||||
March 31, | |||||||||||||||||||
2015 | 2014 | ||||||||||||||||||
Derivatives in cash flow hedging relationships: | |||||||||||||||||||
Commodity derivatives | $ | 1 | $ | (4 | ) | ||||||||||||||
Total | $ | 1 | $ | (4 | ) | ||||||||||||||
Location of Gain/(Loss) | Amount of Gain/(Loss) | ||||||||||||||||||
Reclassified from | Reclassified from AOCI into Income | ||||||||||||||||||
AOCI into Income | (Effective Portion) | ||||||||||||||||||
(Effective Portion) | Three Months Ended | ||||||||||||||||||
March 31, | |||||||||||||||||||
2015 | 2014 | ||||||||||||||||||
Derivatives in cash flow hedging relationships: | |||||||||||||||||||
Commodity derivatives | Cost of products sold | $ | — | $ | (4 | ) | |||||||||||||
Total | $ | — | $ | (4 | ) | ||||||||||||||
Location of Gain/(Loss) | Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | ||||||||||||||||||
Recognized in Income | |||||||||||||||||||
on Derivatives | Three Months Ended | ||||||||||||||||||
March 31, | |||||||||||||||||||
2015 | 2014 | ||||||||||||||||||
Derivatives in fair value hedging relationships (including hedged item): | |||||||||||||||||||
Commodity derivatives | Cost of products sold | $ | (3 | ) | $ | (6 | ) | ||||||||||||
Total | $ | (3 | ) | $ | (6 | ) | |||||||||||||
Location of Gain/(Loss) | Amount of Gain/(Loss) Recognized in Income on Derivatives | ||||||||||||||||||
Recognized in Income | |||||||||||||||||||
on Derivatives | Three Months Ended | ||||||||||||||||||
March 31, | |||||||||||||||||||
2015 | 2014 | ||||||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives – Trading | Cost of products sold | $ | (2 | ) | $ | 7 | |||||||||||||
Commodity derivatives – Non-trading | Cost of products sold | (8 | ) | (6 | ) | ||||||||||||||
Interest rate derivatives | Losses on interest rate derivatives | (77 | ) | (2 | ) | ||||||||||||||
Embedded derivatives | Other income | 2 | (1 | ) | |||||||||||||||
Total | $ | (85 | ) | $ | (2 | ) |
Related_Party_Transactions
Related Party Transactions | 3 Months Ended |
Mar. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED PARTY TRANSACTIONS: |
The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and on behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements. | |
In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions. | |
In addition, ETE recorded sales with affiliates of $76 million and $328 million during the three months ended March 31, 2015 and 2014, respectively. |
Other_Information
Other Information | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Other Information [Abstract] | ||||||||
Other Information | OTHER INFORMATION: | |||||||
The tables below present additional detail for certain balance sheet captions. | ||||||||
Other Current Assets | ||||||||
Other current assets consisted of the following: | ||||||||
March 31, | December 31, 2014 | |||||||
2015 | ||||||||
Deposits paid to vendors | $ | 62 | $ | 65 | ||||
Deferred income taxes | 11 | 14 | ||||||
Income taxes receivable | 110 | 17 | ||||||
Prepaid expenses and other | 228 | 205 | ||||||
Total other current assets | $ | 411 | $ | 301 | ||||
Accrued and Other Current Liabilities | ||||||||
Accrued and other current liabilities consisted of the following: | ||||||||
March 31, | December 31, 2014 | |||||||
2015 | ||||||||
Interest payable | $ | 461 | $ | 440 | ||||
Customer advances and deposits | 99 | 103 | ||||||
Accrued capital expenditures | 655 | 673 | ||||||
Accrued wages and benefits | 136 | 233 | ||||||
Taxes payable other than income taxes | 249 | 236 | ||||||
Income taxes payable | 42 | 54 | ||||||
Deferred income taxes | 99 | 99 | ||||||
Other | 267 | 363 | ||||||
Total accrued and other current liabilities | $ | 2,008 | $ | 2,201 | ||||
Reportable_Segments
Reportable Segments | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Segment Reporting [Abstract] | ||||||||
Reportable Segments | REPORTABLE SEGMENTS: | |||||||
Our financial statements reflect the following reportable business segments: | ||||||||
•Investment in ETP, including the consolidated operations of ETP; | ||||||||
• | Investment in Regency, including the consolidated operations of Regency; | |||||||
• | Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and | |||||||
• | Corporate and Other, including the following: | |||||||
• | activities of the Parent Company; and | |||||||
• | the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. | |||||||
Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. | ||||||||
We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation. | ||||||||
Eliminations in the tables below include the following: | ||||||||
• | ETP’s Segment Adjusted EBITDA reflected 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA included its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star were included in eliminations. | |||||||
The following tables present financial information by segment: | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Segment Adjusted EBITDA: | ||||||||
Investment in ETP | $ | 1,149 | $ | 1,206 | ||||
Investment in Regency | 282 | 205 | ||||||
Investment in Lake Charles LNG | 49 | 48 | ||||||
Corporate and Other | (23 | ) | (26 | ) | ||||
Adjustments and Eliminations | (62 | ) | (58 | ) | ||||
Total | 1,395 | 1,375 | ||||||
Depreciation, depletion and amortization | (493 | ) | (373 | ) | ||||
Interest expense, net of interest capitalized | (371 | ) | (315 | ) | ||||
Gain on sale of AmeriGas common units | — | 70 | ||||||
Losses on interest rate derivatives | (77 | ) | (2 | ) | ||||
Non-cash unit-based compensation expense | (23 | ) | (20 | ) | ||||
Unrealized losses on commodity risk management activities | (75 | ) | (33 | ) | ||||
Inventory valuation adjustments | (34 | ) | 14 | |||||
Equity in earnings of unconsolidated affiliates | 57 | 104 | ||||||
Adjusted EBITDA related to unconsolidated affiliates | (146 | ) | (210 | ) | ||||
Adjusted EBITDA related to discontinued operations | — | (27 | ) | |||||
Other, net | — | (14 | ) | |||||
Income from continuing operations before income tax expense | $ | 233 | $ | 569 | ||||
March 31, 2015 | December 31, 2014 | |||||||
Assets: | ||||||||
Investment in ETP | $ | 50,629 | $ | 48,221 | ||||
Investment in Regency | 17,416 | 17,103 | ||||||
Investment in Lake Charles LNG | 1,255 | 1,210 | ||||||
Corporate and Other | 645 | 1,153 | ||||||
Adjustments and Eliminations | (2,941 | ) | (3,218 | ) | ||||
Total assets | $ | 67,004 | $ | 64,469 | ||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Revenues: | ||||||||
Investment in ETP: | ||||||||
Revenues from external customers | $ | 9,475 | $ | 12,212 | ||||
Intersegment revenues | 55 | 20 | ||||||
9,530 | 12,232 | |||||||
Investment in Regency: | ||||||||
Revenues from external customers | 867 | 806 | ||||||
Intersegment revenues | 132 | 57 | ||||||
999 | 863 | |||||||
Investment in Lake Charles LNG: | ||||||||
Revenues from external customers | 54 | 54 | ||||||
Adjustments and Eliminations | (203 | ) | (69 | ) | ||||
Total revenues | $ | 10,380 | $ | 13,080 | ||||
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP, Regency and Lake Charles LNG. | ||||||||
Investment in ETP | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Intrastate Transportation and Storage | $ | 550 | $ | 847 | ||||
Interstate Transportation and Storage | 271 | 295 | ||||||
Midstream | 255 | 302 | ||||||
Liquids Transportation and Services | 813 | 801 | ||||||
Investment in Sunoco Logistics | 2,526 | 4,452 | ||||||
Retail Marketing | 4,782 | 5,008 | ||||||
All Other | 333 | 527 | ||||||
Total revenues | 9,530 | 12,232 | ||||||
Less: Intersegment revenues | 55 | 20 | ||||||
Revenues from external customers | $ | 9,475 | $ | 12,212 | ||||
Investment in Regency | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Gathering and Processing | $ | 887 | $ | 793 | ||||
Contract Services | 84 | 63 | ||||||
Natural Resources | 25 | 2 | ||||||
Corporate and Other | 3 | 5 | ||||||
Total revenues | 999 | 863 | ||||||
Less: Intersegment revenues | 132 | 57 | ||||||
Revenues from external customers | $ | 867 | $ | 806 | ||||
Investment in Lake Charles LNG | ||||||||
Lake Charles LNG’s revenues of $54 million and $54 million for the three months ended March 31, 2015 and 2014, respectively, were related to LNG terminalling. |
Supplemental_Financial_Stateme
Supplemental Financial Statement Information | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Supplemental Financial Statement Information | ||||||||
Supplemental Financial Statement Information | SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION: | |||||||
Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis: | ||||||||
BALANCE SHEETS | ||||||||
(unaudited) | ||||||||
March 31, | December 31, 2014 | |||||||
2015 | ||||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
Cash and cash equivalents | $ | 4 | $ | 2 | ||||
Accounts receivable from related companies | 17 | 14 | ||||||
Other current assets | 1 | 1 | ||||||
Total current assets | 22 | 17 | ||||||
PROPERTY, PLANT AND EQUIPMENT | 5 | — | ||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 6,304 | 5,390 | ||||||
INTANGIBLE ASSETS, net | 9 | 10 | ||||||
GOODWILL | 9 | 9 | ||||||
OTHER NON-CURRENT ASSETS, net | 55 | 46 | ||||||
Total assets | $ | 6,404 | $ | 5,472 | ||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
CURRENT LIABILITIES: | ||||||||
Accounts payable to related companies | $ | 25 | $ | 11 | ||||
Interest payable | 66 | 58 | ||||||
Accrued and other current liabilities | 1 | 3 | ||||||
Total current liabilities | 92 | 72 | ||||||
LONG-TERM DEBT, less current maturities | 5,507 | 4,680 | ||||||
NOTE PAYABLE TO AFFILIATE | 95 | 54 | ||||||
OTHER NON-CURRENT LIABILITIES | 3 | 2 | ||||||
COMMITMENTS AND CONTINGENCIES | ||||||||
PARTNERS’ CAPITAL: | ||||||||
General Partner | (1 | ) | (1 | ) | ||||
Limited Partners: | ||||||||
Common Unitholders | 695 | 648 | ||||||
Class D Units | 18 | 22 | ||||||
Accumulated other comprehensive loss | (5 | ) | (5 | ) | ||||
Total partners’ capital | 707 | 664 | ||||||
Total liabilities and partners’ capital | $ | 6,404 | $ | 5,472 | ||||
STATEMENTS OF OPERATIONS | ||||||||
(unaudited) | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (28 | ) | $ | (31 | ) | ||
OTHER INCOME (EXPENSE): | ||||||||
Interest expense, net of interest capitalized | (61 | ) | (40 | ) | ||||
Equity in earnings of unconsolidated affiliates | 373 | 239 | ||||||
Other, net | 1 | — | ||||||
INCOME BEFORE INCOME TAXES | 285 | 168 | ||||||
Income tax expense | 1 | — | ||||||
NET INCOME | 284 | 168 | ||||||
General Partner’s interest in net income | 1 | — | ||||||
Class D Unitholder’s interest in net income | 1 | 1 | ||||||
Limited Partners’ interest in net income | $ | 282 | $ | 167 | ||||
STATEMENTS OF CASH FLOWS | ||||||||
(unaudited) | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 198 | $ | 229 | ||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Cash paid for Bakken Pipeline Transaction | (817 | ) | — | |||||
Contributions to unconsolidated affiliate | — | (7 | ) | |||||
Capital expenditures | (5 | ) | — | |||||
Cash received from affiliate | 54 | — | ||||||
Net cash used in investing activities | (768 | ) | (7 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from borrowings | 1,692 | 405 | ||||||
Principal payments on debt | (865 | ) | (56 | ) | ||||
Distributions to partners | (244 | ) | (195 | ) | ||||
Units repurchased under buyback program | — | (366 | ) | |||||
Debt issuance costs | (11 | ) | (2 | ) | ||||
Net cash provided by (used in) financing activities | 572 | (214 | ) | |||||
INCREASE IN CASH AND CASH EQUIVALENTS | 2 | 8 | ||||||
CASH AND CASH EQUIVALENTS, beginning of period | 2 | 8 | ||||||
CASH AND CASH EQUIVALENTS, end of period | $ | 4 | $ | 16 | ||||
Operations_And_Organization_Ac
Operations And Organization Accounting policy (Policies) | 3 Months Ended |
Mar. 31, 2015 | |
Accounting Policies [Abstract] | |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Pronouncement |
In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810) (“ASU 2015-02”), which changed the requirements for consolidations analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2016, and we are currently evaluating the impact that it will have on our consolidated financial statements and related disclosures. |
Advances_to_and_Investments_in1
Advances to and Investments in Unconsolidated Affiliates (Tables) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
INVESTMENTS IN UNCONSOLIDATED AFFILIATES [Abstract] | ||||||||
Investments in and Advances to Affiliates, Schedule of Investments [Text Block] | The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented). | |||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Revenue | $ | 1,428 | $ | 1,819 | ||||
Operating income | 553 | 464 | ||||||
Net income | 437 | 344 | ||||||
Cash_And_Cash_Equivalents_Tabl
Cash And Cash Equivalents (Tables) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Supplemental Cash Flow Information [Abstract] | ||||||||
Schedule Of Non-Cash Investing and Non-Cash Financing Activities | Non-cash investing and financing activities were as follows: | |||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
NON-CASH INVESTING ACTIVITIES: | ||||||||
Accrued capital expenditures | $ | 658 | $ | 192 | ||||
Net gains from subsidiary common unit issuances | $ | — | $ | 603 | ||||
NON-CASH FINANCING ACTIVITIES: | ||||||||
Subsidiary issuances of common units in connection with acquisitions | $ | — | $ | 4,015 | ||||
Long-term debt assumed in PVR Acquisition | $ | — | $ | 1,887 | ||||
Inventories_Tables
Inventories (Tables) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Inventory, Net [Abstract] | ||||||||
Schedule Of Inventory | Inventories consisted of the following: | |||||||
March 31, | December 31, | |||||||
2015 | 2014 | |||||||
Natural gas and NGLs | $ | 294 | $ | 392 | ||||
Crude oil | 470 | 364 | ||||||
Refined products | 367 | 392 | ||||||
Other | 330 | 319 | ||||||
Total inventories | $ | 1,461 | $ | 1,467 | ||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 3 Months Ended | |||||||||||||||
Mar. 31, 2015 | ||||||||||||||||
Fair Value Measurements [Abstract] | ||||||||||||||||
Fair Value Of Financial Assets And Liabilities Measured 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 March 31, 2015 and December 31, 2014 based on inputs used to derive their fair values: | |||||||||||||||
Fair Value Measurements at | ||||||||||||||||
31-Mar-15 | ||||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Total | ||||||||||||||||
Assets: | ||||||||||||||||
Interest rate derivatives | $ | 6 | $ | — | $ | 6 | $ | — | ||||||||
Commodity derivatives: | ||||||||||||||||
Condensate — Forward Swaps | 35 | — | 35 | — | ||||||||||||
Natural Gas: | ||||||||||||||||
Basis Swaps IFERC/NYMEX | 11 | 11 | — | — | ||||||||||||
Swing Swaps IFERC | 2 | — | 2 | — | ||||||||||||
Fixed Swaps/Futures | 317 | 295 | 22 | — | ||||||||||||
Forward Physical Swaps | 1 | — | 1 | — | ||||||||||||
Natural Gas Liquids — Forwards/Swaps | 42 | 25 | 17 | — | ||||||||||||
Power: | ||||||||||||||||
Forwards | 5 | — | 5 | — | ||||||||||||
Futures | 4 | 4 | — | — | ||||||||||||
Options — Calls | 2 | 2 | — | — | ||||||||||||
Refined Products — Futures | 7 | 7 | — | — | ||||||||||||
Crude – Futures | 2 | 2 | — | — | ||||||||||||
Total commodity derivatives | 428 | 346 | 82 | — | ||||||||||||
Total assets | $ | 434 | $ | 346 | $ | 88 | $ | — | ||||||||
Liabilities: | ||||||||||||||||
Interest rate derivatives | $ | (226 | ) | $ | — | $ | (226 | ) | $ | — | ||||||
Embedded derivatives in the Regency Preferred Units | (14 | ) | — | — | (14 | ) | ||||||||||
Commodity derivatives: | ||||||||||||||||
Condensate — Forward Swaps | (1 | ) | — | (1 | ) | — | ||||||||||
Natural Gas: | ||||||||||||||||
Basis Swaps IFERC/NYMEX | (10 | ) | (10 | ) | — | — | ||||||||||
Swing Swaps IFERC | (4 | ) | (1 | ) | (3 | ) | — | |||||||||
Fixed Swaps/Futures | (293 | ) | (293 | ) | — | — | ||||||||||
Natural Gas Liquids — Forwards/Swaps | (22 | ) | (22 | ) | — | — | ||||||||||
Power: | ||||||||||||||||
Forwards | (4 | ) | — | (4 | ) | — | ||||||||||
Futures | (3 | ) | (3 | ) | — | — | ||||||||||
Options — Puts | (4 | ) | (4 | ) | — | — | ||||||||||
Refined Products — Futures | (5 | ) | (5 | ) | — | — | ||||||||||
Crude — Futures | (3 | ) | (3 | ) | — | — | ||||||||||
Total commodity derivatives | (349 | ) | (341 | ) | (8 | ) | — | |||||||||
Total liabilities | $ | (589 | ) | $ | (341 | ) | $ | (234 | ) | $ | (14 | ) | ||||
Fair Value Measurements at | ||||||||||||||||
31-Dec-14 | ||||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Total | ||||||||||||||||
Assets: | ||||||||||||||||
Interest rate derivatives | $ | 3 | $ | — | $ | 3 | $ | — | ||||||||
Commodity derivatives: | ||||||||||||||||
Condensate — Forward Swaps | 36 | — | 36 | — | ||||||||||||
Natural Gas: | ||||||||||||||||
Basis Swaps IFERC/NYMEX | 19 | 19 | — | — | ||||||||||||
Swing Swaps IFERC | 26 | 1 | 25 | — | ||||||||||||
Fixed Swaps/Futures | 566 | 541 | 25 | — | ||||||||||||
Forward Physical Contracts | 1 | — | 1 | — | ||||||||||||
Power: | ||||||||||||||||
Forwards | 3 | — | 3 | — | ||||||||||||
Futures | 4 | 4 | — | — | ||||||||||||
Natural Gas Liquids — Forwards/Swaps | 69 | 46 | 23 | — | ||||||||||||
Refined Products — Futures | 21 | 21 | — | — | ||||||||||||
Total commodity derivatives | 745 | 632 | 113 | — | ||||||||||||
Total assets | $ | 748 | $ | 632 | $ | 116 | $ | — | ||||||||
Liabilities: | ||||||||||||||||
Interest rate derivatives | $ | (155 | ) | $ | — | $ | (155 | ) | $ | — | ||||||
Embedded derivatives in the Regency Preferred Units | (16 | ) | — | — | (16 | ) | ||||||||||
Natural Gas: | ||||||||||||||||
Basis Swaps IFERC/NYMEX | (18 | ) | (18 | ) | — | — | ||||||||||
Swing Swaps IFERC | (25 | ) | (2 | ) | (23 | ) | — | |||||||||
Fixed Swaps/Futures | (490 | ) | (490 | ) | — | — | ||||||||||
Power: | ||||||||||||||||
Forwards | (4 | ) | — | (4 | ) | — | ||||||||||
Futures | (2 | ) | (2 | ) | — | — | ||||||||||
Natural Gas Liquids — Forwards/Swaps | (32 | ) | (32 | ) | — | — | ||||||||||
Refined Products — Futures | (7 | ) | (7 | ) | — | — | ||||||||||
Total commodity derivatives | (578 | ) | (551 | ) | (27 | ) | — | |||||||||
Total liabilities | $ | (749 | ) | $ | (551 | ) | $ | (182 | ) | $ | (16 | ) | ||||
Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis | The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the three months ended March 31, 2015. | |||||||||||||||
Balance, December 31, 2014 | $ | (16 | ) | |||||||||||||
Net unrealized gains included in other income (expense) | 2 | |||||||||||||||
Balance, March 31, 2015 | $ | (14 | ) |
Net_Income_per_Limited_Partner1
Net Income per Limited Partner Unit (Tables) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Earnings Per Share [Abstract] | ||||||||
Reconciliation Of Net Income And Weighted Average Units | 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 | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Income from continuing operations | $ | 221 | $ | 424 | ||||
Less: Income from continuing operations attributable to noncontrolling interest | (63 | ) | 259 | |||||
Income from continuing operations, net of noncontrolling interest | 284 | 165 | ||||||
Less: General Partner’s interest in income from continuing operations | 1 | — | ||||||
Less: Class D Unitholder’s interest in income from continuing operations | 1 | 1 | ||||||
Income from continuing operations available to Limited Partners | $ | 282 | $ | 164 | ||||
Basic Income from Continuing Operations per Limited Partner Unit: | ||||||||
Weighted average limited partner units | 538.8 | 557.7 | ||||||
Basic income from continuing operations per Limited Partner unit | $ | 0.52 | $ | 0.3 | ||||
Basic income from discontinued operations per Limited Partner unit | $ | 0 | $ | 0 | ||||
Diluted Income from Continuing Operations per Limited Partner Unit: | ||||||||
Income from continuing operations available to Limited Partners | $ | 282 | $ | 164 | ||||
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder | (1 | ) | (1 | ) | ||||
Diluted income from continuing operations available to Limited Partners | $ | 281 | $ | 163 | ||||
Weighted average limited partner units | 538.8 | 557.7 | ||||||
Dilutive effect of unconverted unit awards | 0.7 | 0.7 | ||||||
Weighted average limited partner units, assuming dilutive effect of unvested unit awards | 539.5 | 558.4 | ||||||
Diluted income from continuing operations per Limited Partner unit | $ | 0.52 | $ | 0.3 | ||||
Diluted income from discontinued operations per Limited Partner unit | $ | 0 | $ | 0 | ||||
Equity_Tables
Equity (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Schedule of Net IDR Subsidies [Table Text Block] | In connection with previous transactions, including the Regency Merger, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on ETP Class I Units. | ||||||||
Total Year | |||||||||
2015 (remainder) | $ | 84 | |||||||
2016 | 137 | ||||||||
2017 | 145 | ||||||||
2018 | 140 | ||||||||
2019 | 130 | ||||||||
2020 | 35 | ||||||||
2021 | 35 | ||||||||
2022 | 35 | ||||||||
2023 | 35 | ||||||||
2024 | 18 | ||||||||
Change In ETE Common Units | The change in ETE Common Units during the three months ended March 31, 2015 was as follows: | ||||||||
Number of | |||||||||
Units | |||||||||
Outstanding at December 31, 2014 | 538.8 | ||||||||
Conversion of Class D Units to ETE Common Units | 0.5 | ||||||||
Outstanding at March 31, 2015 | 539.3 | ||||||||
Accumulated Other Comprehensive Income | The following table presents the components of AOCI, net of tax: | ||||||||
March 31, | December 31, 2014 | ||||||||
2015 | |||||||||
Available-for-sale securities | $ | 4 | $ | 3 | |||||
Foreign currency translation adjustment | (5 | ) | (3 | ) | |||||
Net loss on commodity related hedges | — | (1 | ) | ||||||
Actuarial loss related to pensions and other postretirement benefits | (12 | ) | (57 | ) | |||||
Investments in unconsolidated affiliates, net | — | 2 | |||||||
Subtotal | (13 | ) | (56 | ) | |||||
Amounts attributable to noncontrolling interest | 8 | 51 | |||||||
Total AOCI, net of tax | $ | (5 | ) | $ | (5 | ) | |||
Parent Company [Member] | |||||||||
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Following are distributions declared and/or paid by us subsequent to December 31, 2014: | ||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
December 31, 2014 | February 6, 2015 | February 19, 2015 | $ | 0.45 | |||||
March 31, 2015 | 8-May-15 | 19-May-15 | 0.49 | ||||||
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, 2014: | ||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
31-Dec-14 | February 6, 2015 | February 13, 2015 | $ | 0.995 | |||||
March 31, 2015 | 8-May-15 | 15-May-15 | 1.015 | ||||||
Regency [Member] | |||||||||
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Following are distributions declared and/or paid by Regency subsequent to December 31, 2014: | ||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
31-Dec-14 | February 6, 2015 | February 13, 2015 | $ | 0.5025 | |||||
Sunoco Logistics [Member] | |||||||||
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2014: | ||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
31-Dec-14 | 9-Feb-15 | 13-Feb-15 | $ | 0.4 | |||||
31-Mar-15 | 11-May-15 | 15-May-15 | 0.419 | ||||||
Sunoco LP [Member] | |||||||||
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Sunoco LP Quarterly Distributions of Available Cash | ||||||||
Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2014: | |||||||||
Quarter Ended | Record Date | Payment Date | Rate | ||||||
31-Dec-14 | February 17, 2015 | February 27, 2015 | $ | 0.6 | |||||
31-Mar-15 | 19-May-15 | 29-May-15 | 0.645 | ||||||
Regulatory_Matters_Commitments1
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Acrrued Environmental Liabilities [Abstract] | ||||||||
Schedule of Rent Expense [Table Text Block] | We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: | |||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Rental expense(1) | $ | 52 | $ | 32 | ||||
Less: Sublease rental income | (8 | ) | (8 | ) | ||||
Rental expense, net | $ | 44 | $ | 24 | ||||
(1) | Includes contingent rentals totaling | |||||||
Environmental Exit Costs by Cost | 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. | |||||||
March 31, | 31-Dec-14 | |||||||
2015 | ||||||||
Current | $ | 48 | $ | 41 | ||||
Non-current | 340 | 360 | ||||||
Total environmental liabilities | $ | 388 | $ | 401 | ||||
Price_Risk_Management_Assets_A1
Price Risk Management Assets And Liabilities (Tables) | 3 Months Ended | ||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | |||||||||||||||||||
Location of Gain/(Loss) | Amount of Gain/(Loss) Recognized in Income on Derivatives | ||||||||||||||||||
Recognized in Income | |||||||||||||||||||
on Derivatives | Three Months Ended | ||||||||||||||||||
March 31, | |||||||||||||||||||
2015 | 2014 | ||||||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives – Trading | Cost of products sold | $ | (2 | ) | $ | 7 | |||||||||||||
Commodity derivatives – Non-trading | Cost of products sold | (8 | ) | (6 | ) | ||||||||||||||
Interest rate derivatives | Losses on interest rate derivatives | (77 | ) | (2 | ) | ||||||||||||||
Embedded derivatives | Other income | 2 | (1 | ) | |||||||||||||||
Total | $ | (85 | ) | $ | (2 | ) | |||||||||||||
Interest Rate Swaps Outstanding | The following table summarizes our interest rate swaps outstanding none of which were designated as hedges for accounting purposes: | ||||||||||||||||||
Notional Amount | |||||||||||||||||||
Outstanding | |||||||||||||||||||
Entity | Term | Type(1) | March 31, | December 31, 2014 | |||||||||||||||
2015 | |||||||||||||||||||
ETP | July 2015(2) | Forward-starting to pay a fixed rate of 3.40% and receive a floating rate | $ | 100 | $ | 200 | |||||||||||||
ETP | July 2016(3) | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | 200 | 200 | |||||||||||||||
ETP | July 2017(4) | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | 300 | 300 | |||||||||||||||
ETP | July 2018(4) | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | 200 | 200 | |||||||||||||||
ETP | July 2019(4) | Forward-starting to pay a fixed rate of 3.01% and receive a floating rate | 500 | 300 | |||||||||||||||
ETP | Mar-19 | Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53% | 600 | — | |||||||||||||||
ETP | Feb-23 | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | — | 200 | |||||||||||||||
(1) | Floating rates are based on 3-month LIBOR. | ||||||||||||||||||
(2) | Represents the effective date. These forward starting swaps have a term 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 a term 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 | ||||||||||||||||||
March 31, 2015 | December 31, 2014 | March 31, 2015 | December 31, 2014 | ||||||||||||||||
Derivatives designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives (margin deposits) | $ | 3 | $ | 43 | $ | — | $ | — | |||||||||||
3 | 43 | — | — | ||||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||||
Commodity derivatives (margin deposits) | $ | 347 | $ | 617 | $ | (346 | ) | $ | (577 | ) | |||||||||
Commodity derivatives | 94 | 107 | (19 | ) | (23 | ) | |||||||||||||
Interest rate derivatives | 6 | 3 | (226 | ) | (155 | ) | |||||||||||||
Embedded derivatives in Regency Preferred Units | — | — | (14 | ) | (16 | ) | |||||||||||||
447 | 727 | (605 | ) | (771 | ) | ||||||||||||||
Total derivatives | $ | 450 | $ | 770 | $ | (605 | ) | $ | (771 | ) | |||||||||
Derivatives, Offsetting Fair Value Amounts [Table Text Block] | The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: | ||||||||||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||||||||||
Balance Sheet Location | March 31, 2015 | December 31, 2014 | March 31, 2015 | December 31, 2014 | |||||||||||||||
Derivatives in offsetting agreements: | |||||||||||||||||||
OTC contracts | Price risk management asset (liability) | $ | 20 | $ | 23 | $ | (18 | ) | $ | (23 | ) | ||||||||
Broker cleared derivative contracts | Other current assets | 334 | 674 | (356 | ) | (574 | ) | ||||||||||||
354 | 697 | (374 | ) | (597 | ) | ||||||||||||||
Offsetting agreements: | |||||||||||||||||||
Counterparty netting | Price risk management asset (liability) | (14 | ) | (19 | ) | 14 | 19 | ||||||||||||
Payments on margin deposit | Other current assets | 30 | 5 | (4 | ) | (22 | ) | ||||||||||||
16 | (14 | ) | 10 | (3 | ) | ||||||||||||||
Net derivatives with offsetting agreements | 370 | 683 | (364 | ) | (600 | ) | |||||||||||||
Derivatives without offsetting agreements | 80 | 87 | (241 | ) | (171 | ) | |||||||||||||
Total derivatives | $ | 450 | $ | 770 | $ | (605 | ) | $ | (771 | ) | |||||||||
Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives | 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 | |||||||||||||||||||
March 31, | |||||||||||||||||||
2015 | 2014 | ||||||||||||||||||
Derivatives in cash flow hedging relationships: | |||||||||||||||||||
Commodity derivatives | $ | 1 | $ | (4 | ) | ||||||||||||||
Total | $ | 1 | $ | (4 | ) | ||||||||||||||
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block] | |||||||||||||||||||
Location of Gain/(Loss) | Amount of Gain/(Loss) | ||||||||||||||||||
Reclassified from | Reclassified from AOCI into Income | ||||||||||||||||||
AOCI into Income | (Effective Portion) | ||||||||||||||||||
(Effective Portion) | Three Months Ended | ||||||||||||||||||
March 31, | |||||||||||||||||||
2015 | 2014 | ||||||||||||||||||
Derivatives in cash flow hedging relationships: | |||||||||||||||||||
Commodity derivatives | Cost of products sold | $ | — | $ | (4 | ) | |||||||||||||
Total | $ | — | $ | (4 | ) | ||||||||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | |||||||||||||||||||
Location of Gain/(Loss) | Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | ||||||||||||||||||
Recognized in Income | |||||||||||||||||||
on Derivatives | Three Months Ended | ||||||||||||||||||
March 31, | |||||||||||||||||||
2015 | 2014 | ||||||||||||||||||
Derivatives in fair value hedging relationships (including hedged item): | |||||||||||||||||||
Commodity derivatives | Cost of products sold | $ | (3 | ) | $ | (6 | ) | ||||||||||||
Total | $ | (3 | ) | $ | (6 | ) | |||||||||||||
ETP [Member] | |||||||||||||||||||
Outstanding Commodity-Related Derivatives | The following table details ETP’s outstanding commodity-related derivatives: | ||||||||||||||||||
March 31, 2015 | December 31, 2014 | ||||||||||||||||||
Notional | Maturity | Notional | Maturity | ||||||||||||||||
Volume | Volume | ||||||||||||||||||
Mark-to-Market Derivatives | |||||||||||||||||||
(Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Fixed Swaps/Futures | 775,000 | 2015 | (232,500 | ) | 2015 | ||||||||||||||
Basis Swaps IFERC/NYMEX (1) | 3,842,500 | 2015-2016 | (13,907,500 | ) | 2015-2016 | ||||||||||||||
Options – Calls | 5,000,000 | 2015 | 5,000,000 | 2015 | |||||||||||||||
Power (Megawatt): | |||||||||||||||||||
Forwards | 225,131 | 2015 | 288,775 | 2015 | |||||||||||||||
Futures | 168,992 | 2015 | (156,000 | ) | 2015 | ||||||||||||||
Options — Puts | (177,942 | ) | 2015 | (72,000 | ) | 2015 | |||||||||||||
Options — Calls | 1,742,117 | 2015 | 198,556 | 2015 | |||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | 13,292,500 | 2015-2016 | 57,500 | 2015 | |||||||||||||||
Swing Swaps IFERC | 51,465,000 | 2015-2016 | 46,150,000 | 2015 | |||||||||||||||
Fixed Swaps/Futures | 1,705,000 | 2015-2016 | (8,779,000 | ) | 2015-2016 | ||||||||||||||
Forward Physical Contracts | 23,903,779 | 2015 | (9,116,777 | ) | 2015 | ||||||||||||||
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps | (768,100 | ) | 2015-2016 | (2,179,400 | ) | 2015 | |||||||||||||
Refined Products (Bbls) — Futures | (1,019,000 | ) | 2015 | 13,745,755 | 2015 | ||||||||||||||
Fair Value Hedging Derivatives | |||||||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu): | |||||||||||||||||||
Basis Swaps IFERC/NYMEX | (23,295,000 | ) | 2016 | (39,287,500 | ) | 2015 | |||||||||||||
Fixed Swaps/Futures | (23,475,000 | ) | 2016 | (39,287,500 | ) | 2015 | |||||||||||||
Hedged Item — Inventory | 23,475,000 | 2016 | 39,287,500 | 2015 | |||||||||||||||
(1) | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations | ||||||||||||||||||
Regency [Member] | |||||||||||||||||||
Outstanding Commodity-Related Derivatives | The following table details Regency’s outstanding commodity-related derivatives: | ||||||||||||||||||
March 31, 2015 | December 31, 2014 | ||||||||||||||||||
Notional | Maturity | Notional | Maturity | ||||||||||||||||
Volume | Volume | ||||||||||||||||||
Mark-to-Market Derivatives | |||||||||||||||||||
(Non-Trading) | |||||||||||||||||||
Natural Gas (MMBtu) — Fixed Swaps/Futures | (17,875,000 | ) | 2015 | (25,525,000 | ) | 2015 | |||||||||||||
Propane (Gallons) — Forwards/Swaps | (21,966,000 | ) | 2015 | (29,148,000 | ) | 2015 | |||||||||||||
NGLs (Barrels) — Forwards/Swaps | (220,000 | ) | 2015 | (292,000 | ) | 2015 | |||||||||||||
WTI Crude Oil (Barrels) — Forwards/Swaps | (1,060,000 | ) | 2015-2016 | (1,252,000 | ) | 2015-2016 |
Other_Information_Tables
Other Information (Tables) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Other Information [Abstract] | ||||||||
Other Current Assets | Other current assets consisted of the following: | |||||||
March 31, | December 31, 2014 | |||||||
2015 | ||||||||
Deposits paid to vendors | $ | 62 | $ | 65 | ||||
Deferred income taxes | 11 | 14 | ||||||
Income taxes receivable | 110 | 17 | ||||||
Prepaid expenses and other | 228 | 205 | ||||||
Total other current assets | $ | 411 | $ | 301 | ||||
Accrued And Other Current Liabilities | Accrued and other current liabilities consisted of the following: | |||||||
March 31, | December 31, 2014 | |||||||
2015 | ||||||||
Interest payable | $ | 461 | $ | 440 | ||||
Customer advances and deposits | 99 | 103 | ||||||
Accrued capital expenditures | 655 | 673 | ||||||
Accrued wages and benefits | 136 | 233 | ||||||
Taxes payable other than income taxes | 249 | 236 | ||||||
Income taxes payable | 42 | 54 | ||||||
Deferred income taxes | 99 | 99 | ||||||
Other | 267 | 363 | ||||||
Total accrued and other current liabilities | $ | 2,008 | $ | 2,201 | ||||
Reportable_Segments_Tables
Reportable Segments (Tables) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Operating Segments [Member] | ||||||||
Financial Information By Segment | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Segment Adjusted EBITDA: | ||||||||
Investment in ETP | $ | 1,149 | $ | 1,206 | ||||
Investment in Regency | 282 | 205 | ||||||
Investment in Lake Charles LNG | 49 | 48 | ||||||
Corporate and Other | (23 | ) | (26 | ) | ||||
Adjustments and Eliminations | (62 | ) | (58 | ) | ||||
Total | 1,395 | 1,375 | ||||||
Depreciation, depletion and amortization | (493 | ) | (373 | ) | ||||
Interest expense, net of interest capitalized | (371 | ) | (315 | ) | ||||
Gain on sale of AmeriGas common units | — | 70 | ||||||
Losses on interest rate derivatives | (77 | ) | (2 | ) | ||||
Non-cash unit-based compensation expense | (23 | ) | (20 | ) | ||||
Unrealized losses on commodity risk management activities | (75 | ) | (33 | ) | ||||
Inventory valuation adjustments | (34 | ) | 14 | |||||
Equity in earnings of unconsolidated affiliates | 57 | 104 | ||||||
Adjusted EBITDA related to unconsolidated affiliates | (146 | ) | (210 | ) | ||||
Adjusted EBITDA related to discontinued operations | — | (27 | ) | |||||
Other, net | — | (14 | ) | |||||
Income from continuing operations before income tax expense | $ | 233 | $ | 569 | ||||
Assets Segments [Member] | ||||||||
Financial Information By Segment | ||||||||
March 31, 2015 | December 31, 2014 | |||||||
Assets: | ||||||||
Investment in ETP | $ | 50,629 | $ | 48,221 | ||||
Investment in Regency | 17,416 | 17,103 | ||||||
Investment in Lake Charles LNG | 1,255 | 1,210 | ||||||
Corporate and Other | 645 | 1,153 | ||||||
Adjustments and Eliminations | (2,941 | ) | (3,218 | ) | ||||
Total assets | $ | 67,004 | $ | 64,469 | ||||
Sales Revenue, Segment [Member] | ||||||||
Financial Information By Segment | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Revenues: | ||||||||
Investment in ETP: | ||||||||
Revenues from external customers | $ | 9,475 | $ | 12,212 | ||||
Intersegment revenues | 55 | 20 | ||||||
9,530 | 12,232 | |||||||
Investment in Regency: | ||||||||
Revenues from external customers | 867 | 806 | ||||||
Intersegment revenues | 132 | 57 | ||||||
999 | 863 | |||||||
Investment in Lake Charles LNG: | ||||||||
Revenues from external customers | 54 | 54 | ||||||
Adjustments and Eliminations | (203 | ) | (69 | ) | ||||
Total revenues | $ | 10,380 | $ | 13,080 | ||||
Investment In ETP [Member] | ||||||||
Revenue from External Customers by Products and Services [Table Text Block] | Investment in ETP | |||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Intrastate Transportation and Storage | $ | 550 | $ | 847 | ||||
Interstate Transportation and Storage | 271 | 295 | ||||||
Midstream | 255 | 302 | ||||||
Liquids Transportation and Services | 813 | 801 | ||||||
Investment in Sunoco Logistics | 2,526 | 4,452 | ||||||
Retail Marketing | 4,782 | 5,008 | ||||||
All Other | 333 | 527 | ||||||
Total revenues | 9,530 | 12,232 | ||||||
Less: Intersegment revenues | 55 | 20 | ||||||
Revenues from external customers | $ | 9,475 | $ | 12,212 | ||||
Investment In Regency [Member] | ||||||||
Revenue from External Customers by Products and Services [Table Text Block] | Investment in Regency | |||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
Gathering and Processing | $ | 887 | $ | 793 | ||||
Contract Services | 84 | 63 | ||||||
Natural Resources | 25 | 2 | ||||||
Corporate and Other | 3 | 5 | ||||||
Total revenues | 999 | 863 | ||||||
Less: Intersegment revenues | 132 | 57 | ||||||
Revenues from external customers | $ | 867 | $ | 806 | ||||
Supplemental_Financial_Stateme1
Supplemental Financial Statement Information (Tables) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Parent [Member] | ||||||||
Schedule Of Balance Sheets | BALANCE SHEETS | |||||||
(unaudited) | ||||||||
March 31, | December 31, 2014 | |||||||
2015 | ||||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
Cash and cash equivalents | $ | 4 | $ | 2 | ||||
Accounts receivable from related companies | 17 | 14 | ||||||
Other current assets | 1 | 1 | ||||||
Total current assets | 22 | 17 | ||||||
PROPERTY, PLANT AND EQUIPMENT | 5 | — | ||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 6,304 | 5,390 | ||||||
INTANGIBLE ASSETS, net | 9 | 10 | ||||||
GOODWILL | 9 | 9 | ||||||
OTHER NON-CURRENT ASSETS, net | 55 | 46 | ||||||
Total assets | $ | 6,404 | $ | 5,472 | ||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
CURRENT LIABILITIES: | ||||||||
Accounts payable to related companies | $ | 25 | $ | 11 | ||||
Interest payable | 66 | 58 | ||||||
Accrued and other current liabilities | 1 | 3 | ||||||
Total current liabilities | 92 | 72 | ||||||
LONG-TERM DEBT, less current maturities | 5,507 | 4,680 | ||||||
NOTE PAYABLE TO AFFILIATE | 95 | 54 | ||||||
OTHER NON-CURRENT LIABILITIES | 3 | 2 | ||||||
COMMITMENTS AND CONTINGENCIES | ||||||||
PARTNERS’ CAPITAL: | ||||||||
General Partner | (1 | ) | (1 | ) | ||||
Limited Partners: | ||||||||
Common Unitholders | 695 | 648 | ||||||
Class D Units | 18 | 22 | ||||||
Accumulated other comprehensive loss | (5 | ) | (5 | ) | ||||
Total partners’ capital | 707 | 664 | ||||||
Total liabilities and partners’ capital | $ | 6,404 | $ | 5,472 | ||||
Schedule Of Statements Of Operations | STATEMENTS OF OPERATIONS | |||||||
(unaudited) | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (28 | ) | $ | (31 | ) | ||
OTHER INCOME (EXPENSE): | ||||||||
Interest expense, net of interest capitalized | (61 | ) | (40 | ) | ||||
Equity in earnings of unconsolidated affiliates | 373 | 239 | ||||||
Other, net | 1 | — | ||||||
INCOME BEFORE INCOME TAXES | 285 | 168 | ||||||
Income tax expense | 1 | — | ||||||
NET INCOME | 284 | 168 | ||||||
General Partner’s interest in net income | 1 | — | ||||||
Class D Unitholder’s interest in net income | 1 | 1 | ||||||
Limited Partners’ interest in net income | $ | 282 | $ | 167 | ||||
Parent Company [Member] | ||||||||
Schedule Of Statements Of Cash Flows | STATEMENTS OF CASH FLOWS | |||||||
(unaudited) | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
2015 | 2014 | |||||||
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 198 | $ | 229 | ||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Cash paid for Bakken Pipeline Transaction | (817 | ) | — | |||||
Contributions to unconsolidated affiliate | — | (7 | ) | |||||
Capital expenditures | (5 | ) | — | |||||
Cash received from affiliate | 54 | — | ||||||
Net cash used in investing activities | (768 | ) | (7 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from borrowings | 1,692 | 405 | ||||||
Principal payments on debt | (865 | ) | (56 | ) | ||||
Distributions to partners | (244 | ) | (195 | ) | ||||
Units repurchased under buyback program | — | (366 | ) | |||||
Debt issuance costs | (11 | ) | (2 | ) | ||||
Net cash provided by (used in) financing activities | 572 | (214 | ) | |||||
INCREASE IN CASH AND CASH EQUIVALENTS | 2 | 8 | ||||||
CASH AND CASH EQUIVALENTS, beginning of period | 2 | 8 | ||||||
CASH AND CASH EQUIVALENTS, end of period | $ | 4 | $ | 16 | ||||
Operations_And_Organization_Na
Operations And Organization Narrative (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
FEP [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 50.00% | |
Citrus [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 50.00% | |
Trunkline LNG [Member] | ||
LNG Storage Capacity | 9 | |
ETP [Member] | Lone Star L.L.C. [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 70.00% | |
ETP [Member] | Susser [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |
ETP [Member] | Sunoco LP [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 44.00% | |
Fayetteville Express Pipeline, LLC [Member] | FEP [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |
FGT [Member] | FEP [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |
Regency [Member] | Lone Star L.L.C. [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 30.00% | |
Retail Marketing [Member] | ||
Excise Taxes Collected | $736 | $530 |
Acquisitions_Narrative_Details
Acquisitions Narrative (Details) (USD $) | 1 Months Ended | 3 Months Ended | 1 Months Ended | 12 Months Ended | |
In Millions, except Share data, unless otherwise specified | Apr. 30, 2015 | Mar. 31, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 |
Regency Merger [Member] | |||||
Number of Regency Common Units to be Issued in Acquisition Per Share | 0.4124 | ||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 172,200,000 | ||||
IDR Subsidies | $320 | ||||
Dropdown of Sunoco LLC Interest [Member] | |||||
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage | 31.58% | ||||
Gallons of motor fuel distributed | 5,300,000,000 | ||||
Business Combination, Consideration Transferred | 816 | ||||
Payments to Acquire Businesses, Gross | 775 | ||||
Equity Issued in Business Combination, Fair Value Disclosure | 41 | ||||
Bakken Pipeline Transaction [Member] | |||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 30,800,000 | ||||
Payments to Acquire Businesses, Gross | 879 | ||||
Class H Interest in Sunoco Logistics | 90.05% | 90.05% | |||
Interest ownership | 45.00% | 45.00% | |||
Class I Distributions | 30 | 55 | |||
ETP [Member] | |||||
Incentive Distribution Rights | 100.00% | 100.00% | |||
ETP Subsidiaries [Member] | Regency Merger [Member] | |||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 15,500,000 | ||||
ETP Series A Preferred Units [Member] | Regency Merger [Member] | |||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 1,900,000 | ||||
Class H Units [Member] | |||||
Business Acquisition Units Acquired | 50,200,000 | 50,200,000 | |||
Class H Units [Member] | Bakken Pipeline Transaction [Member] | |||||
Business Acquisition Units Acquired | 30,800,000 | 30,800,000 | |||
Class I Units [Member] | Bakken Pipeline Transaction [Member] | |||||
Business Acquisition Units Acquired | 100 | 100 | |||
First year post closing [Member] | Regency Merger [Member] | |||||
IDR Subsidies | 80 | ||||
Four years post closing [Member] | Regency Merger [Member] | |||||
IDR Subsidies | 60 |
Advances_to_and_Investments_in2
Advances to and Investments in Unconsolidated Affiliates Narrative (Details) | 1 Months Ended | 3 Months Ended |
In Millions, unless otherwise specified | Jan. 31, 2014 | Mar. 31, 2015 |
AmeriGas [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
AmeriGas common units sold by ETP | 9.2 | |
Investment Owned, Balance, Shares | 3.1 | |
Citrus [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Interest ownership | 50.00% | |
FGT [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Percentage Ownership Operating Facility | 100.00% | |
Fayetteville Express Pipeline, LLC [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Interest ownership | 50.00% | |
RIGS Haynesville Partnership Co. [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Interest ownership | 49.99% | |
Midcontinent Express Pipeline, LLC [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Interest ownership | 50.00% |
Advances_to_and_Investments_in3
Advances to and Investments in Unconsolidated Affiliates Table - Selected I/S Data (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Schedule of Equity Method Investments [Line Items] | ||
Revenue | $1,428 | $1,819 |
Operating income | 553 | 464 |
Net income | $437 | $344 |
Cash_And_Cash_Equivalents_Tabl1
Cash And Cash Equivalents Table - Schedule of Non-Cash Investing & Financing Activities (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
NON-CASH INVESTING ACTIVITIES: | ||
Accrued capital expenditures | $658 | $192 |
Net gains from subsidiary common unit issuances | 0 | 603 |
NON-CASH FINANCING ACTIVITIES: | ||
Subsidiary issuances of common units in connection with acquisitions | 0 | 4,015 |
Long-term debt assumed in PVR Acquisition | $0 | $1,887 |
Inventories_Table_Inventory_Ba
Inventories Table - Inventory Balances (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Inventory, Net [Abstract] | ||
Natural gas and NGLs | $294 | $392 |
Crude oil | 470 | 364 |
Refined products | 367 | 392 |
Other | 330 | 319 |
Total inventories | $1,461 | $1,467 |
Fair_Value_Measurements_Narrat
Fair Value Measurements Narrative (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Dec. 31, 2014 | |
Fair Value Measurements [Abstract] | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net | $0 | |
Debt obligations, fair value | 35,150,000,000 | 31,680,000,000 |
Long-term Debt | $33,427,000,000 | $30,661,000,000 |
Fair_Value_Measurements_Table_
Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Liabilities, Fair Value Disclosure, Recurring | ($589) | ($749) |
Fair Value, Inputs, Level 1 [Member] | ||
Liabilities, Fair Value Disclosure, Recurring | -341 | -551 |
Fair Value, Inputs, Level 2 [Member] | ||
Liabilities, Fair Value Disclosure, Recurring | -234 | -182 |
Level 3 [Member] | ||
Liabilities, Fair Value Disclosure, Recurring | -14 | -16 |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Commodity Derivatives - Crude Oil [Member] | Future [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | -3 | |
Commodity Derivatives - Crude Oil [Member] | Fair Value, Inputs, Level 1 [Member] | Future [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | -3 | |
Commodity Derivatives - Crude Oil [Member] | Fair Value, Inputs, Level 2 [Member] | Future [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Commodity Derivatives - Crude Oil [Member] | Level 3 [Member] | Future [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | ||
Interest Rate Derivative Assets, at Fair Value | 6 | 3 |
Price Risk Derivative Assets, at Fair Value | 428 | 745 |
Assets, Fair Value Disclosure | 434 | 748 |
Interest Rate Derivative Liabilities, at Fair Value | -226 | -155 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | -14 | -16 |
Price Risk Derivative Liabilities, at Fair Value | -349 | -578 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Interest Rate Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Assets, at Fair Value | 346 | 632 |
Assets, Fair Value Disclosure | 346 | 632 |
Interest Rate Derivative Liabilities, at Fair Value | 0 | 0 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | -341 | -551 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Interest Rate Derivative Assets, at Fair Value | 6 | 3 |
Price Risk Derivative Assets, at Fair Value | 82 | 113 |
Assets, Fair Value Disclosure | 88 | 116 |
Interest Rate Derivative Liabilities, at Fair Value | -226 | -155 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | -8 | -27 |
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | ||
Interest Rate Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Assets, Fair Value Disclosure | 0 | 0 |
Interest Rate Derivative Liabilities, at Fair Value | 0 | 0 |
Embedded Derivative, Fair Value of Embedded Derivative Liability | -14 | -16 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 35 | 36 |
Price Risk Derivative Liabilities, at Fair Value | -1 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 35 | 36 |
Price Risk Derivative Liabilities, at Fair Value | -1 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 3 [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ||
Price Risk Derivative Assets, at Fair Value | 11 | 19 |
Price Risk Derivative Liabilities, at Fair Value | -10 | -18 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | 26 |
Price Risk Derivative Liabilities, at Fair Value | -4 | -25 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 317 | 566 |
Price Risk Derivative Liabilities, at Fair Value | -293 | -490 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Basis Swaps IFERC/NYMEX [Member] | ||
Price Risk Derivative Assets, at Fair Value | 11 | 19 |
Price Risk Derivative Liabilities, at Fair Value | -10 | -18 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Swing Swaps IFERC [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 1 |
Price Risk Derivative Liabilities, at Fair Value | -1 | -2 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 295 | 541 |
Price Risk Derivative Liabilities, at Fair Value | -293 | -490 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 2 [Member] | Basis Swaps IFERC/NYMEX [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 2 [Member] | Swing Swaps IFERC [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | 25 |
Price Risk Derivative Liabilities, at Fair Value | -3 | -23 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 22 | 25 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Basis Swaps IFERC/NYMEX [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Swing Swaps IFERC [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 7 | 21 |
Price Risk Derivative Liabilities, at Fair Value | -5 | -7 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Inputs, Level 1 [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 7 | 21 |
Price Risk Derivative Liabilities, at Fair Value | -5 | -7 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Inputs, Level 2 [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 5 | 3 |
Price Risk Derivative Liabilities, at Fair Value | -4 | -4 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 4 | |
Price Risk Derivative Liabilities, at Fair Value | -3 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Put Option [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | -4 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Call Option [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 4 | |
Price Risk Derivative Liabilities, at Fair Value | -2 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 4 | |
Price Risk Derivative Liabilities, at Fair Value | -3 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 1 [Member] | Put Option [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | -4 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 1 [Member] | Call Option [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 1 [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 4 | |
Price Risk Derivative Liabilities, at Fair Value | -2 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 5 | 3 |
Price Risk Derivative Liabilities, at Fair Value | -4 | -4 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 2 [Member] | Put Option [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 2 [Member] | Call Option [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 2 [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Put Option [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Call Option [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 42 | 69 |
Price Risk Derivative Liabilities, at Fair Value | -22 | -32 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 25 | 46 |
Price Risk Derivative Liabilities, at Fair Value | -22 | -32 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 17 | 23 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 3 [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude Oil [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude Oil [Member] | Fair Value, Inputs, Level 1 [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude Oil [Member] | Fair Value, Inputs, Level 2 [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude Oil [Member] | Level 3 [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | $0 |
Fair_Value_Measurements_Table_1
Fair Value Measurements Table - Reconciliation of Level 3 Derivatives (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Net unrealized gains included in other income (expense) | $2 | |
Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | ||
Balance, December 31, 2014 | -16 | |
Balance, March 31, 2015 | ($14) | ($16) |
Net_Income_per_Limited_Partner2
Net Income per Limited Partner Unit Table - Income Reconciliation (Details) (USD $) | 3 Months Ended | |
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items] | ||
Income from continuing operations | $221 | $424 |
Less: Income from continuing operations attributable to noncontrolling interest | -63 | 259 |
Income from continuing operations, net of noncontrolling interest | 284 | 165 |
Less: General Partner’s interest in income from continuing operations | 1 | 0 |
Less: Class D Unitholder’s interest in income from continuing operations | 1 | 1 |
Income from continuing operations available to Limited Partners | 282 | 164 |
Basic Income from Continuing Operations per Limited Partner Unit: | ||
Weighted average Limited Partner units | 538.8 | 557.7 |
Basic income from continuing operations per Limited Partner unit | $0.52 | $0.30 |
Basic income from discontinued operations per Limited Partner unit | $0 | $0 |
Diluted Income from Continuing Operations per Limited Partner Unit: | ||
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder | -1 | -1 |
Diluted income from continuing operations available to Limited Partners | $281 | $163 |
Dilutive effect of unconverted unit awards | 0.7 | 0.7 |
Weighted average limited partner units, assuming dilutive effect of unvested unit awards | 539.5 | 558.4 |
Diluted income from continuing operations per Limited Partner unit | $0.52 | $0.30 |
Diluted income from discontinued operations per Limited Partner unit | $0 | $0 |
Debt_Obligations_Narrative_Det
Debt Obligations Narrative (Details) (USD $) | 1 Months Ended | 3 Months Ended | |
Apr. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | |
4.05% Senior Notes due March 2025 [Member] | ETP [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes | 1,000,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.05% | ||
4.90% Senior Notes due March 2035 [Member] | ETP [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes | 500,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.90% | ||
5.15% Senior Notes due March 2045 [Member] | ETP [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes | 1,000,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.15% | ||
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes | 800,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.38% | ||
5.875% Senior Notes due January 15, 2024 [Member] | Parent Company [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes | 1,150,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.88% | ||
ETE Senior Secured Revolving Credit Facilities [Member] | Parent Company [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Current Borrowing Capacity | 1,500,000,000 | ||
Line of Credit Facility, Amount Outstanding | 925,000,000 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 575,000,000 | ||
ETE 7.5% Senior Notes due 2020 [Member] | Parent Company [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes | 1,190,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 7.50% | ||
ETP Revolving Credit Facility, due October 2017 [Member] | ETP [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Current Borrowing Capacity | 3,750,000,000 | ||
Line of Credit Facility, Amount Outstanding | 0 | ||
Line of Credit Facility, Increase (Decrease), Net | 1,500,000,000 | ||
Regency Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Amount Outstanding | 2,090,000,000 | ||
Letters of Credit Outstanding, Amount | 16,000,000 | ||
Line of Credit Facility, Maximum Borrowing Capacity | 2,500,000,000 | ||
Sunoco Logistics Revolving Credit Facility, due March 2020 [Member] | Sunoco Logistics [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Current Borrowing Capacity | 2,500,000,000 | 1,500,000,000 | |
Line of Credit Facility, Amount Outstanding | 350,000,000 | ||
Line of Credit Facility, Maximum Borrowing Capacity | 3,250,000,000 | ||
Sunoco LP Revolving Credit Facility Due September 2019 [Member] | Sunoco LP [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Current Borrowing Capacity | 1,500,000,000 | 1,250,000,000 | |
Line Of Credit Facility, Additional Borrowing Capacity Subject To Lender Approval | 250,000,000 | ||
Line of Credit Facility, Amount Outstanding | 685,000,000 | ||
LIBOR Rate Loans [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | 3.25% | ||
Base Rate Loans [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | 2.25% | ||
After increase in capacity [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Current Borrowing Capacity | 2,250,000,000 | ||
Increase in term loan [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Current Borrowing Capacity | 850,000,000 |
Equity_Narrative_Details
Equity Narrative (Details) (USD $) | 3 Months Ended | 1 Months Ended | 12 Months Ended | |||
Mar. 31, 2015 | Apr. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Stock Issued During Period, Shares, New Issues | 500,000 | |||||
ETP [Member] | ||||||
Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount | 1,330,000,000 | $1,330,000,000 | ||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | 59,000,000 | |||||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 1,000,000 | |||||
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan | 6,300,000 | 6,300,000 | ||||
Regency [Member] | ||||||
Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount | 1,000,000,000 | 1,000,000,000 | ||||
Sunoco Logistics [Member] | ||||||
Proceeds from Issuance of Common Stock, net | 547,000,000 | 82,000,000 | ||||
Partners' Capital Account, Units, Sale of Units | 13,500,000 | |||||
Stock Issued During Period, Shares, New Issues | 2,000,000 | |||||
Equity distribution agreement [Member] | ETP [Member] | ||||||
Proceeds from Issuance of Common Stock, net | 76,000,000 | |||||
Fees and Commissions | 1,000,000 | |||||
Equity distribution agreement [Member] | Regency [Member] | ||||||
Proceeds from Issuance of Common Limited Partners Units | 34,000,000 | |||||
Equity distribution agreement [Member] | Sunoco Logistics [Member] | ||||||
Proceeds from Issuance of Common Limited Partners Units | 142,000,000 | |||||
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units | 1,250,000,000 | |||||
Fees and Commissions | 1,000,000 | |||||
Class H Units [Member] | ||||||
Business Acquisition Units Acquired | 50,200,000 | 50,200,000 | ||||
Sunoco Logistics Revolving Credit Facility, due March 2020 [Member] | Sunoco Logistics [Member] | ||||||
Line of Credit Facility, Current Borrowing Capacity | 2,500,000,000 | 2,500,000,000 | 1,500,000,000 | |||
Bakken Pipeline Transaction [Member] | ||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 30,800,000 | |||||
Interest ownership | 45.00% | 45.00% | ||||
Payments to Acquire Businesses, Gross | 879,000,000 | |||||
Class H Interest in Sunoco Logistics | 90.05% | 90.05% | ||||
Class I Distributions | $30,000,000 | $55,000,000 | ||||
Bakken Pipeline Transaction [Member] | Class H Units [Member] | ||||||
Business Acquisition Units Acquired | 30,800,000 | 30,800,000 | ||||
Bakken Pipeline Transaction [Member] | Class I Units [Member] | ||||||
Business Acquisition Units Acquired | 100 | 100 |
Equity_Table_Change_In_ETE_Com
Equity Table - Change In ETE Common Units (Details) | 3 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 |
Partners' Capital Notes [Abstract] | |
Outstanding at December 31, 2014 | 538.8 |
Stock Issued During Period, Shares, New Issues | 0.5 |
Outstanding at March 31, 2015 | 539.3 |
Equity_Table_Quarterly_Distrib
Equity Table - Quarterly Distributions of Available Cash (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Dec. 31, 2014 | |
Regency [Member] | ||
Distribution Made to Limited Partner, Date of Record | 6-Feb-15 | |
Distribution Made to Limited Partner, Distribution Date | 13-Feb-15 | |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $0.50 | |
Sunoco Logistics [Member] | ||
Distribution Made to Limited Partner, Date of Record | 11-May-15 | 9-Feb-15 |
Distribution Made to Limited Partner, Distribution Date | 15-May-15 | 13-Feb-15 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $0.42 | $0.40 |
Parent Company [Member] | ||
Distribution Made to Limited Partner, Date of Record | 8-May-15 | 6-Feb-15 |
Distribution Made to Limited Partner, Distribution Date | 19-May-15 | 19-Feb-15 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $0.49 | $0.45 |
ETP [Member] | ||
Distribution Made to Limited Partner, Date of Record | 8-May-15 | 6-Feb-15 |
Distribution Made to Limited Partner, Distribution Date | 15-May-15 | 13-Feb-15 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $1.01 | $1.00 |
Sunoco Logistics [Member] | ||
Distribution Made to Limited Partner, Date of Record | 19-May-15 | 17-Feb-15 |
Distribution Made to Limited Partner, Distribution Date | 29-May-15 | 27-Feb-15 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $0.65 | $0.60 |
Equity_Table_IDR_Schedule_Deta
Equity Table - IDR Schedule (Details) (USD $) | 9 Months Ended | 12 Months Ended | ||||||||
In Millions, unless otherwise specified | Dec. 31, 2015 | Dec. 31, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Equity [Abstract] | ||||||||||
Relinquishment of Rights of Incentive Distributions | $84 | $18 | $35 | $35 | $35 | $35 | $130 | $140 | $145 | $137 |
Equity_Table_Accumulated_Other
Equity Table - Accumulated Other Comprehensive Income (Details) (USD $) | 3 Months Ended | 12 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Partners' Capital Notes [Abstract] | ||
Available-for-sale securities | $4 | $3 |
Foreign currency translation adjustment | -5 | -3 |
Net loss on commodity related hedges | 0 | -1 |
Actuarial loss related to pensions and other postretirement benefits | -12 | -57 |
Investments in unconsolidated affiliates, net | 0 | 2 |
Subtotal | -13 | -56 |
Amounts attributable to noncontrolling interest | 8 | 51 |
Accumulated other comprehensive income, net | ($5) | ($5) |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 |
Favorable [Member] | |
Tax Adjustments, Settlements, and Unusual Provisions | $14 |
Unfavorable [Member] | |
Tax Adjustments, Settlements, and Unusual Provisions | 85 |
Sunoco [Member] | |
Increase (Decrease) in Tax Refund Adjustment | 92 |
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | ($464) |
Regulatory_Matters_Commitments2
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details) (USD $) | 3 Months Ended | 1 Months Ended | |||||||
Mar. 31, 2015 | Mar. 31, 2014 | Nov. 30, 2012 | Sep. 30, 2013 | Jan. 31, 2012 | Dec. 31, 2014 | Apr. 30, 2013 | |||
Lease Expiration Date | 31-Dec-58 | ||||||||
Operating Leases, Rent Expense | $52,000,000 | [1] | $32,000,000 | [1] | |||||
Operating Leases, Rent Expense, Contingent Rentals | 4,000,000 | 3,000,000 | |||||||
Loss Contingency Accrual, at Carrying Value | 39,000,000 | 37,000,000 | |||||||
Amounts recorded in balance sheets for contingencies and current litigation not disclosed | 0 | ||||||||
Payments for Environmental Liabilities | 7,000,000 | 8,000,000 | |||||||
Environmental Costs Recognized, Recovery Credited to Expense | 19,000,000 | ||||||||
Compensatory Damages [Member] | |||||||||
Gain Contingency, Unrecorded Amount | 319,000,000 | ||||||||
Disgorgement [Member] | |||||||||
Gain Contingency, Unrecorded Amount | 595,000,000 | ||||||||
Expense Reimbursement [Member] | |||||||||
Gain Contingency, Unrecorded Amount | 1,000,000 | ||||||||
Final Judgement [Member] | |||||||||
Gain Contingency, Unrecorded Amount | 536,000,000 | ||||||||
Regency 4.50% Senior Notes Due 2023 [Member] | |||||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.50% | ||||||||
Guarantor Obligations, Current Carrying Value | 600,000,000 | ||||||||
FGT [Member] | |||||||||
Proceeds from Legal Settlements | 100,000,000 | ||||||||
FGT [Member] | I-595 Project [Member] | |||||||||
Loss Contingency, Damages Awarded, Value | 19,000,000 | ||||||||
FGT [Member] | Turnpike/State Road 91 [Member] | |||||||||
Loss Contingency, Damages Awarded, Value | 1,000,000 | ||||||||
AmeriGas [Member] | |||||||||
Contingent Residual Support Agreement, Amount | $1,550,000,000 | ||||||||
Southern Union [Member] | |||||||||
Percentage Of Recovery | 50.00% | ||||||||
Loss Contingency, Estimated Recovery from Third Party | 150000 | ||||||||
Sunoco [Member] | |||||||||
Site Contingency, Number of Sites Needing Remediation | 51 | ||||||||
[1] | (1)Â Includes contingent rentals totaling |
Regulatory_Matters_Commitments3
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Environmental Exit Cost [Line Items] | ||
Current | $48 | $41 |
Non-current | 340 | 360 |
Total environmental liabilities | $388 | $401 |
Regulatory_Matters_Commitments4
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Rent expense table (Details) (USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | ||
Operating Leases, Rent Expense | $52 | [1] | $32 | [1] |
Operating Leases, Rent Expense, Sublease Rentals | 8 | 8 | ||
Operating Leases, Rent Expense, Net | $44 | $24 | ||
[1] | (1)Â Includes contingent rentals totaling |
Price_Risk_Management_Assets_A2
Price Risk Management Assets And Liabilities Narrative (Details) (Regency [Member], USD $) | 3 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 |
Regency [Member] | |
Proceeds From Termination of Commodity Swaps | $56 |
Notional Amount of Credit Risk Derivatives | 72 |
Derivative, Fair Value, Amount Offset Against Collateral, Net | $1 |
Price_Risk_Management_Assets_A3
Price Risk Management Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2015 | Dec. 31, 2014 | |||
Megawatt | Megawatt | |||
Mark-To-Market Derivatives [Member] | Power [Member] | Call Option [Member] | ETP [Member] | ||||
Notional Volume | 1,742,117 | 198,556 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Mark-To-Market Derivatives [Member] | Power [Member] | Forwards Swaps [Member] | ETP [Member] | ||||
Notional Volume | 225,131 | 288,775 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Mark-To-Market Derivatives [Member] | Power [Member] | Future [Member] | ETP [Member] | ||||
Notional Volume | 168,992 | -156,000 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Mark-To-Market Derivatives [Member] | Power [Member] | Options - Puts [Member] | ETP [Member] | ||||
Notional Volume | -177,942 | -72,000 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | Future [Member] | ||||
Notional Volume | -1,019,000 | 13,745,755 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member] | ||||
Notional Volume | 3,842,500 | [1] | -13,907,500 | [1] |
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member] | ||||
Notional Volume | 5,000,000 | 5,000,000 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member] | ||||
Notional Volume | 775,000 | -232,500 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2016 | 2016 | ||
Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member] | ||||
Notional Volume | -768,100 | -2,179,400 | ||
Maximum Term Of Commodity Derivatives | 2015 | |||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member] | ||||
Notional Volume | -1,060,000 | -1,252,000 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas Liquids [Member] | Forwards Swaps [Member] | Regency [Member] | ||||
Notional Volume | -220,000 | -292,000 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member] | ||||
Notional Volume | 13,292,500 | 57,500 | ||
Maximum Term Of Commodity Derivatives | 2015 | |||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member] | ||||
Notional Volume | 51,465,000 | 46,150,000 | ||
Maximum Term Of Commodity Derivatives | 2015 | |||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member] | ||||
Notional Volume | 1,705,000 | -8,779,000 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member] | ||||
Notional Volume | -17,875,000 | -25,525,000 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | ETP [Member] | ||||
Notional Volume | 23,903,779 | -9,116,777 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards Swaps [Member] | Regency [Member] | ||||
Notional Volume | -21,966,000 | -29,148,000 | ||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2016 | |||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member] | ||||
Maximum Term Of Commodity Derivatives | 2016 | 2016 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2016 | |||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2016 | |||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2016 | 2016 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2015 | |||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member] | ||||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2015 | |||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2015 | |||
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member] | ||||
Maximum Term Of Commodity Derivatives | 2015 | 2015 | ||
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member] | ||||
Notional Volume | -23,295,000 | -39,287,500 | ||
Maximum Term Of Commodity Derivatives | 2016 | 2015 | ||
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member] | ||||
Notional Volume | -23,475,000 | -39,287,500 | ||
Maximum Term Of Commodity Derivatives | 2016 | 2015 | ||
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | ETP [Member] | ||||
Notional Volume | 23,475,000 | 39,287,500 | ||
Maximum Term Of Commodity Derivatives | 2016 | 2015 | ||
[1] | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Price_Risk_Management_Assets_A4
Price Risk Management Assets And Liabilities Table - Interest Rate Swaps Outstanding (Details) (Interest Rate Derivatives [Member], ETP [Member], USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | ||
March 2019 [Member] | ||||
Notional Amount | $600 | $0 | ||
Type | Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53% | [1] | ||
February 2023 [Member] | ||||
Notional Amount | 0 | 200 | ||
Type | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | |||
Forward-Starting Swaps [Member] | July 2015 [Member] | ||||
Notional Amount | 100 | [2] | 200 | [2] |
Type | Forward-starting to pay a fixed rate of 3.40% and receive a floating rate | [2] | ||
Forward-Starting Swaps [Member] | July 2016 [Member] | ||||
Notional Amount | 200 | [3] | 200 | [3] |
Type | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | [3] | ||
Forward-Starting Swaps [Member] | July 2017 [Member] | ||||
Notional Amount | 300 | [4] | 300 | [4] |
Type | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | [4] | ||
Forward-Starting Swaps [Member] | July 2018 [Member] | ||||
Notional Amount | 200 | [4] | 200 | [4] |
Type | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | [4] | ||
Forward-Starting Swaps [Member] | July 2019 [Member] | ||||
Notional Amount | $500 | [4] | $300 | [4] |
Type | Forward-starting to pay a fixed rate of 3.01% and receive a floating rate | [4] | ||
[1] | (1)Â Floating rates are based on 3-month LIBOR. | |||
[2] | (2)Â Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date. | |||
[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 a term 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 Table - Fair Value of Derivative Instruments (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Total derivatives assets | $450 | $770 |
Total derivatives liabilities | 605 | 771 |
Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 3 | 43 |
Total derivatives liabilities | 0 | 0 |
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member] | ||
Total derivatives assets | 3 | 43 |
Total derivatives liabilities | 0 | 0 |
Not Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 447 | 727 |
Total derivatives liabilities | 605 | 771 |
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member] | ||
Total derivatives assets | 347 | 617 |
Total derivatives liabilities | 346 | 577 |
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member] | ||
Total derivatives assets | 94 | 107 |
Total derivatives liabilities | 19 | 23 |
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member] | ||
Total derivatives assets | 6 | 3 |
Total derivatives liabilities | 226 | 155 |
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member] | ||
Total derivatives assets | 0 | 0 |
Total derivatives liabilities | $14 | $16 |
Price_Risk_Management_Assets_A6
Price Risk Management Assets And Liabilities Table - Gross FV and Netting Offset (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $450 | $770 |
Derivative Liability, Fair Value, Gross Liability | -605 | -771 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 16 | -14 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 10 | -3 |
Netting [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 354 | 697 |
Derivative Liability, Fair Value, Gross Liability | -374 | -597 |
Derivative Asset, Fair Value, Gross Liability | -14 | -19 |
Derivative Liability, Fair Value, Gross Asset | 14 | 19 |
Derivative Asset, Fair Value, Net | 370 | 683 |
Derivative Liability, Fair Value, Net | -364 | -600 |
Netting [Member] | OTC contracts [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 20 | 23 |
Derivative Liability, Fair Value, Gross Liability | -18 | -23 |
Netting [Member] | Broker cleared derivative contracts [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 334 | 674 |
Derivative Liability, Fair Value, Gross Liability | -356 | -574 |
Netting [Member] | Asset Fair Value, Netting Offset [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Payments on Margin Deposits | 30 | 5 |
Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value | 80 | 87 |
Netting [Member] | Liability Fair Value, Netting Offset [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Payments on Margin Deposits | -4 | -22 |
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value | ($241) | ($171) |
Price_Risk_Management_Assets_A7
Price Risk Management Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Recognized OCI on Derivatives (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Change in Value Recognized in OCI on Derivatives (Effective Portion) | $1 | ($4) |
Commodity Derivatives [Member] | ||
Change in Value Recognized in OCI on Derivatives (Effective Portion) | $1 | ($4) |
Price_Risk_Management_Assets_A8
Price Risk Management Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Amount of Gain (Loss) Recognized (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | $0 | ($4) |
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness | -3 | -6 |
Amount of Gain/(Loss) Recognized in Income on Derivatives | -85 | -2 |
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member] | ||
Amount of Gain/(Loss) Recognized in Income on Derivatives | -2 | 7 |
Commodity Derivatives [Member] | Cost of Products Sold [Member] | ||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | 0 | -4 |
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness | -3 | -6 |
Amount of Gain/(Loss) Recognized in Income on Derivatives | -8 | -6 |
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member] | ||
Amount of Gain/(Loss) Recognized in Income on Derivatives | -77 | -2 |
Embedded Derivatives [Member] | Other Income (Expenses) [Member] | ||
Amount of Gain/(Loss) Recognized in Income on Derivatives | $2 | ($1) |
Related_Party_Transactions_Rel
Related Party Transactions Related Party Revenue (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Related Party Transactions [Abstract] | ||
Revenue from Related Parties | $76 | $328 |
Other_Information_Table_Other_
Other Information Table - Other Current Assets (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Other Information [Abstract] | ||
Deposits paid to vendors | $62 | $65 |
Deferred income taxes | 11 | 14 |
Income taxes receivable | 110 | 17 |
Prepaid expenses and other | 228 | 205 |
Total other current assets | $411 | $301 |
Other_Information_Table_Accrue
Other Information Table - Accrued and Other Current Liabilities (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Other Information [Abstract] | ||
Interest payable | $461 | $440 |
Customer advances and deposits | 99 | 103 |
Accrued capital expenditures | 655 | 673 |
Accrued wages and benefits | 136 | 233 |
Taxes payable other than income taxes | 249 | 236 |
Income taxes payable | 42 | 54 |
Deferred income taxes | 99 | 99 |
Other | 267 | 363 |
Total accrued and other current liabilities | $2,008 | $2,201 |
Reportable_Segments_Narrative_
Reportable Segments Narrative (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Revenues | $10,380 | $13,080 |
Regency [Member] | Lone Star L.L.C. [Member] | ||
Segment Reporting Information [Line Items] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 30.00% | |
External Customers [Member] | Investment in Lake Charles LNG [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | $54 | $54 |
Reportable_Segments_Table_Segm
Reportable Segments Table - Segment Adjusted EBITDA (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Adjusted EBITDA | $1,395 | $1,375 |
Depreciation, depletion and amortization | -493 | -373 |
Interest Expense, net of interest capitalized | -371 | -315 |
Gain on sale of AmeriGas common units | 0 | 70 |
Losses on interest rate derivatives | -77 | -2 |
Non-cash unit-based compensation expense | -23 | -20 |
Unrealized Gain (Loss) on commodity risk management activities | -75 | -33 |
LIFO valuation adjustment | -34 | 14 |
Equity in earnings of unconsolidated affiliates | 57 | 104 |
Adjusted EBITDA related to unconsolidated affiliates | -146 | -210 |
Adjusted EBITDA related to discontinued operations | 0 | -27 |
Other, net | 0 | -14 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 233 | 569 |
Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Adjusted EBITDA | 1,149 | 1,206 |
Investment In Regency [Member] | ||
Segment Reporting Information [Line Items] | ||
Adjusted EBITDA | 282 | 205 |
Investment in Lake Charles LNG [Member] | ||
Segment Reporting Information [Line Items] | ||
Adjusted EBITDA | 49 | 48 |
Corporate and Other [Member] | ||
Segment Reporting Information [Line Items] | ||
Adjusted EBITDA | -23 | -26 |
Adjustments And Eliminations [Member] | ||
Segment Reporting Information [Line Items] | ||
Adjusted EBITDA | ($62) | ($58) |
Reportable_Segments_Table_Segm1
Reportable Segments Table - Segment Assets (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Assets | $67,004 | $64,469 |
Investment In ETP [Member] | ||
Assets | 50,629 | 48,221 |
Investment In Regency [Member] | ||
Assets | 17,416 | 17,103 |
Investment in Lake Charles LNG [Member] | ||
Assets | 1,255 | 1,210 |
Corporate and Other [Member] | ||
Assets | 645 | 1,153 |
Adjustments And Eliminations [Member] | ||
Assets | ($2,941) | ($3,218) |
Reportable_Segments_Table_Reve
Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Revenues | $10,380 | $13,080 |
Investment In ETP [Member] | ||
Revenues | 9,530 | 12,232 |
Investment In Regency [Member] | ||
Revenues | 999 | 863 |
Adjustments And Eliminations [Member] | ||
Revenues | -203 | -69 |
Intersegment [Member] | Investment In ETP [Member] | ||
Revenues | 55 | 20 |
Intersegment [Member] | Investment In Regency [Member] | ||
Revenues | 132 | 57 |
External Customers [Member] | Investment In ETP [Member] | ||
Revenues | 9,475 | 12,212 |
External Customers [Member] | Investment In Regency [Member] | ||
Revenues | 867 | 806 |
External Customers [Member] | Investment in Lake Charles LNG [Member] | ||
Revenues | $54 | $54 |
Reportable_Segments_Table_Reve1
Reportable Segments Table - Revenues from External Customers by Segment (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Revenues | $10,380 | $13,080 |
Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 9,530 | 12,232 |
Investment In Regency [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 999 | 863 |
Natural Resources [Member] | Investment In Regency [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 25 | 2 |
Gathering And Processing [Member] | Investment In Regency [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 887 | 793 |
Corporate and Other [Member] | Investment In Regency [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 3 | 5 |
Contract Services [Member] | Investment In Regency [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 84 | 63 |
Intersegment [Member] | Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 55 | 20 |
Intersegment [Member] | Investment In Regency [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 132 | 57 |
Other Segments [Member] | Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 333 | 527 |
Liquids Transportation And Services [Member] | Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 813 | 801 |
Midstream [Member] | Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 255 | 302 |
Interstate Transportation and Storage [Member] | Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 271 | 295 |
Intrastate Transportation And Storage [Member] | Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 550 | 847 |
Investment in Sunoco Logistics [Member] | Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 2,526 | 4,452 |
Retail Marketing [Member] | Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 4,782 | 5,008 |
External Customers [Member] | Investment In ETP [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 9,475 | 12,212 |
External Customers [Member] | Investment In Regency [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | $867 | $806 |
Supplemental_Financial_Stateme2
Supplemental Financial Statement Information Table - Balance Sheets (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||||
Cash and cash equivalents | $1,863 | $847 | $1,010 | $590 |
Accounts receivable from related companies | 69 | 35 | ||
Other current assets | 411 | 301 | ||
Total current assets | 6,789 | 6,153 | ||
Property, Plant and Equipment, Net | 42,342 | 40,292 | ||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 3,656 | 3,659 | ||
INTANGIBLE ASSETS, net | 5,553 | 5,582 | ||
GOODWILL | 7,702 | 7,865 | ||
OTHER NON-CURRENT ASSETS, net | 953 | 908 | ||
Total assets | 67,004 | 64,469 | ||
Accounts payable | 2,865 | 3,349 | ||
Accounts payable to related companies | 12 | 19 | ||
Interest payable | 461 | 440 | ||
Price risk management liabilities | 17 | 21 | ||
Accrued and other current liabilities | 2,008 | 2,201 | ||
Current maturities of long-term debt | 269 | 1,008 | ||
Total current liabilities | 5,327 | 6,782 | ||
LONG-TERM DEBT, less current maturities | 33,158 | 29,653 | ||
PREFERRED UNITS OF SUBSIDIARY | 33 | 33 | ||
OTHER NON-CURRENT LIABILITIES | 1,313 | 1,193 | ||
COMMITMENTS AND CONTINGENCIES | ||||
General Partner | -1 | -1 | ||
Common Unitholders | 695 | 648 | ||
Class D Units | 18 | 22 | ||
Accumulated other comprehensive loss | -5 | -5 | ||
Total partners’ capital | 707 | 664 | ||
Total liabilities and equity | 67,004 | 64,469 | ||
Parent Company [Member] | ||||
Cash and cash equivalents | 4 | 2 | 16 | 8 |
Accounts receivable from related companies | 17 | 14 | ||
Other current assets | 1 | 1 | ||
Total current assets | 22 | 17 | ||
Property, Plant and Equipment, Net | 5 | 0 | ||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 6,304 | 5,390 | ||
INTANGIBLE ASSETS, net | 9 | 10 | ||
GOODWILL | 9 | 9 | ||
OTHER NON-CURRENT ASSETS, net | 55 | 46 | ||
Total assets | 6,404 | 5,472 | ||
Accounts payable to related companies | 25 | 11 | ||
Interest payable | 66 | 58 | ||
Accrued and other current liabilities | 1 | 3 | ||
Total current liabilities | 92 | 72 | ||
LONG-TERM DEBT, less current maturities | 5,507 | 4,680 | ||
Notes Payable, Related Parties, Noncurrent | 95 | 54 | ||
OTHER NON-CURRENT LIABILITIES | 3 | 2 | ||
COMMITMENTS AND CONTINGENCIES | ||||
General Partner | -1 | -1 | ||
Common Unitholders | 695 | 648 | ||
Class D Units | 18 | 22 | ||
Accumulated other comprehensive loss | -5 | -5 | ||
Total partners’ capital | 707 | 664 | ||
Total liabilities and equity | $6,404 | $5,472 |
Supplemental_Financial_Stateme3
Supplemental Financial Statement Information Schedule of Statements of Operations (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | ($155) | ($131) |
Interest Expense, net of interest capitalized | -371 | -315 |
Equity in earnings of unconsolidated affiliates | 57 | 104 |
Gains on interest rate derivatives | -77 | -2 |
Other, net | 7 | 2 |
Income tax expense (benefit) | 12 | 145 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 284 | 168 |
General Partner’s interest in net income | 1 | 0 |
Class D Unitholder’s interest in net income | 1 | 1 |
Limited Partners’ interest in net income | 282 | 167 |
Parent Company [Member] | ||
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | -28 | -31 |
Interest Expense, net of interest capitalized | -61 | -40 |
Equity in earnings of unconsolidated affiliates | 373 | 239 |
Other, net | 1 | 0 |
INCOME BEFORE INCOME TAXES | 285 | 168 |
Income tax expense (benefit) | 1 | 0 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 284 | 168 |
General Partner’s interest in net income | 1 | 0 |
Class D Unitholder’s interest in net income | 1 | 1 |
Limited Partners’ interest in net income | $282 | $167 |
Supplemental_Financial_Stateme4
Supplemental Financial Statement Information Schedule Of Statements of Cash Flows (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $575 | $829 |
Cash paid for Bakken Pipeline Transaction | -370 | -214 |
Contributions to unconsolidated affiliates | 34 | 50 |
Capital expenditures | 2,158 | 942 |
Net cash used in investing activities | -2,585 | -801 |
Proceeds from borrowings | 8,731 | 3,170 |
Repayments of long-term debt | -5,938 | -1,977 |
Distributions to partners | 244 | 195 |
Units repurchased under buyback program | 0 | 366 |
Debt issuance costs | -33 | -17 |
Net cash provided by (used in) financing activities | 3,026 | 392 |
INCREASE IN CASH AND CASH EQUIVALENTS | 1,016 | 420 |
CASH AND CASH EQUIVALENTS, beginning of period | 847 | 590 |
CASH AND CASH EQUIVALENTS, end of period | 1,863 | 1,010 |
Parent Company [Member] | ||
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | 198 | 229 |
Cash paid for Bakken Pipeline Transaction | -817 | 0 |
Contributions to unconsolidated affiliates | 0 | 7 |
Capital expenditures | -5 | 0 |
Cash received from affiliate | 54 | 0 |
Net cash used in investing activities | -768 | -7 |
Proceeds from borrowings | 1,692 | 405 |
Repayments of long-term debt | -865 | -56 |
Distributions to partners | -244 | -195 |
Units repurchased under buyback program | 0 | -366 |
Debt issuance costs | -11 | -2 |
Net cash provided by (used in) financing activities | 572 | -214 |
INCREASE IN CASH AND CASH EQUIVALENTS | 2 | 8 |
CASH AND CASH EQUIVALENTS, beginning of period | 2 | 8 |
CASH AND CASH EQUIVALENTS, end of period | $4 | $16 |