Energy Transfer (ET) 10-Q 7 Aug 15 2015 Q2 Quarterly report Financial data

DEI Document

DEI Document - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
Entity Information [Line Items]
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	1,276,187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		1,054,678,036

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
ASSETS
Cash and cash equivalents	$ 1,623	$ 847
Accounts receivable, net	3,186	3,378
Accounts receivable from related companies	124	35
Inventories	1,858	1,467
Exchanges receivable	58	44
Derivative assets	6	81
Other current assets	382	301
Total current assets	7,237	6,153
Property, plant and equipment	49,541	45,018
Accumulated depreciation and depletion	(5,494)	(4,726)
PROPERTY, PLANT AND EQUIPMENT, net	44,047	40,292
Advances to and investments in unconsolidated affiliates	3,653	3,659
Non-current derivative assets	1	10
Other non-current assets, net	965	908
Intangible assets, net	5,579	5,582
Goodwill	7,663	7,865
Total Assets	69,145	64,469
LIABILITIES AND EQUITY
Accounts payable	3,009	3,349
Accounts payable to related companies	7	19
Exchanges payable	137	184
Derivative liabilities	12	21
Accrued and other current liabilities	2,058	2,201
Current maturities of long-term debt	15	1,008
Total current liabilities	5,238	6,782
Long-term debt, less current maturities	34,795	29,653
Deferred income taxes	4,182	4,325
Non-current derivative liabilities	109	154
Other non-current liabilities	$ 1,226	$ 1,193
Commitments and contingencies
Preferred units of subsidiaries	$ 33	$ 33
Redeemable noncontrolling interests	15	15
EQUITY:
General Partner	(1)	(1)
Limited Partners:
Common Unitholders	484	648
Class D Units	20	22
Accumulated other comprehensive loss	(2)	(5)
Total partners’ capital	501	664
Noncontrolling interest	23,046	21,650
Total equity	23,547	22,314
Total Liabilities and Equity	$ 69,145	$ 64,469

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES
Natural gas sales	$ 898	$ 1,362	$ 1,933	$ 2,792
NGL sales	988	1,400	1,969	2,654
Crude sales	2,680	4,432	4,888	8,525
Gathering, transportation and other fees	1,035	878	2,081	1,750
Refined product sales	4,434	4,938	8,090	9,416
Other	1,559	1,133	3,013	2,086
Total revenues	11,594	14,143	21,974	27,223
COSTS AND EXPENSES
Cost of products sold	9,338	12,351	17,825	23,793
Operating expenses	663	428	1,291	852
Depreciation, depletion and amortization	514	450	1,007	823
Selling, general and administrative	183	141	338	272
Total costs and expenses	10,698	13,370	20,461	25,740
OPERATING INCOME	896	773	1,513	1,483
OTHER INCOME (EXPENSE)
Interest expense, net of interest capitalized	(408)	(344)	(779)	(659)
Equity in earnings of unconsolidated affiliates	117	77	174	181
Gains (losses) on extinguishment of debt			(32)	0
Gains (losses) on interest rate derivatives	127	(46)	50	(48)
Gain on sale of AmeriGas common units	0	93	0	163
Other, net	(16)	(25)	(9)	(23)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	716	528	949	1,097
Income tax expense (benefit) from continuing operations	(56)	70	(44)	215
INCOME FROM CONTINUING OPERATIONS	772	458	993	882
Income from discontinued operations	0	42	0	66
NET INCOME	772	500	993	948
Less: Net income attributable to noncontrolling interest	474	336	411	616
NET INCOME ATTRIBUTABLE TO PARTNERS	298	164	582	332
General Partner’s interest in net income	0	1	1	1
Class D Unitholder’s interest in net income	0	0	1	1
Limited Partners’ interest in net income	$ 298	$ 163	$ 580	$ 330
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$ 0.28	$ 0.15	$ 0.54	$ 0.29
Diluted	0.28	0.15	0.54	0.29
NET INCOME PER LIMITED PARTNER UNIT:
Basic	0.28	0.15	0.54	0.30
Diluted	$ 0.28	$ 0.15	$ 0.54	$ 0.30

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income	$ 772	$ 500	$ 993	$ 948
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	0	2	0	6
Change in value of derivative instruments accounted for as cash flow hedges	0	(2)	1	(6)
Change in value of available-for-sale securities	(1)	0	0	0
Actuarial loss relating to pension and other postretirement benefit plans	0	0	45	(1)
Foreign currency translation adjustments	0	1	(2)	(2)
Change in other comprehensive income from unconsolidated affiliates	0	1	(2)	(6)
Other comprehensive income (loss), net of tax	(1)	2	42	(9)
Comprehensive income	771	502	1,035	939
Less: Comprehensive income attributable to noncontrolling interest	470	338	450	610
Comprehensive income attributable to partners	$ 301	$ 164	$ 585	$ 329

Consolidated Statement Of Equit

Consolidated Statement Of Equity - 6 months ended Jun. 30, 2015 - USD ($) $ in Millions	Total	General Partner	Common Unitholders	Class D Units	Accumulated Other Comprehensive Loss	Non- controlling Interest
Balance, December 31, 2014 at Dec. 31, 2014	$ 22,314	$ (1)	$ 648	$ 22	$ (5)	$ 21,650
Distributions to partners	(509)	(1)	(507)	(1)	0	0
Distributions to noncontrolling interest	(1,133)	0	0	0	0	(1,133)
Subsidiary units issued for cash	1,773	0	50	0	0	1,723
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	37	0	0	5	0	32
Capital contributions received from noncontrolling interest	398	0	0	0	0	398
Units repurchased under buyback program	294	0	294		0	0
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	42	0	0	0	3	39
Other, net	(9)	0	0	0	0	(9)
Net income	993	1	580	1	0	411
Balance, June 30, 2015 at Jun. 30, 2015	$ 23,547	$ (1)	$ 484	$ 20	$ (2)	$ 23,046

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
OPERATING ACTIVITIES
Net income	$ 993	$ 948
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,007	823
Deferred income taxes	77	(114)
Amortization included in interest expense	(16)	(28)
Non-cash compensation expense	48	40
Gain on sale of AmeriGas common units	0	(163)
Gains on disposal of assets	(3)	(2)
Gains (losses) on extinguishment of debt	(32)	0
Inventory valuation adjustments	(150)	(34)
Equity in earnings of unconsolidated affiliates	(174)	(181)
Distributions from unconsolidated affiliates	162	143
Other non-cash	23	(38)
Cash flow in operating assets and liabilities, net of effects of acquisitions and deconsolidations	(886)	501
Net cash provided by operating activities	1,113	1,895
INVESTING ACTIVITIES
Cash paid for acquisitions, net of cash received	(475)	(407)
Cash paid for acquisition of a 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	759
Capital expenditures (excluding allowance for equity funds used during construction)	(4,181)	(2,137)
Contributions in aid of construction costs	12	25
Payments to Acquire Interest in Joint Venture	43	70
Distributions from unconsolidated affiliates in excess of cumulative earnings	64	58
Proceeds from Divestiture of Interest in Consolidated Subsidiaries	0	79
Proceeds from the sale of assets	15	18
Increase (Decrease) in Restricted Cash	(8)	(7)
Other	(8)	0
Net cash used in investing activities	(4,673)	(1,668)
FINANCING ACTIVITIES
Proceeds from borrowings	15,466	8,023
Repayments of long-term debt	(11,301)	(5,964)
Subsidiary equity offerings, net of issue costs	1,773	650
Distributions to partners	(509)	(391)
Debt issuance costs	(61)	(44)
Distributions to noncontrolling interest	(1,133)	(863)
Capital contributions received from noncontrolling interest	398	6
Units repurchased under buyback program	(294)	(1,000)
Other, net	(3)	0
Net cash provided by financing activities	4,336	417
Increase in cash and cash equivalents	776	644
Cash and cash equivalents, beginning of period	847	590
Cash and cash equivalents, end of period	$ 1,623	$ 1,234

Operations And Organization

Operations And Organization	6 Months Ended
	Jun. 30, 2015
Operations And Organization [Abstract]
Operations And Organization	ORGANIZATION AND BASIS OF PRESENTATION Organization 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” and ETP’s acquisition of Regency in Note 2 ); • Consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDRs in ETP and Regency (until ETP’s April 2015 acquisition); 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 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 16 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 primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. Subsequent to its acquisition of Regency’s 30% equity interest in Lone Star, ETC OLP now owns 100% of Lone Star. • ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of: • Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales. • ETC 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. • 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, Retail Holdings, owned by ETP and Sunoco, Inc. • Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets. • As of June 30, 2015 , ETP owned an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 44% limited partner interest in Sunoco LP. As discussed in Note 2 , in July 2015, ETP transferred its interest in Susser to Sunoco LP in exchange for cash and additional interests in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP, is a publicly traded Delaware limited partnership that 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 limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the gathering, transportation and terminalling of oil (crude and/or condensate, a lighter oil) received from producers; and the management of coal and natural resource properties in the United States. Regency 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. • 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. Subsequent to ETP’s acquisition of Regency (see Note 2 ), our financial statements reflect the following reportable business segments: • Investment in ETP, including the consolidated operations of ETP; • 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. Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements 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. As discussed in Note 9 , in July 2015, the Partnership completed a two-for-one split of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effect of the unit split for all periods presented. Use of Estimates 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. Excise Taxes The Partnership records 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 the retail marketing operations were $762 million and $573 million for the three months ended June 30, 2015 and 2014 , respectively, and $1.50 billion and $1.10 billion for the six months ended June 30, 2015 and 2014 , respectively. Subsidiary Common Unit Transactions 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. Recent 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	6 Months Ended
	Jun. 30, 2015
ACQUISITIONS AND DIVESTITURE [Abstract]
Acquisitions	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS ETE Proposal to Acquire WMB In June 2015, ETE announced a proposal to merge with WMB. Under the proposed transaction, each issued and outstanding share of WMB common stock would be exchanged for 1.8716 ETE Corp, L.P. common shares (reflecting the recent unit split in July 2015). ETE Corp, L.P. is a recently formed limited partnership that will elect to be treated as a corporation for federal income tax purposes and would own the managing member interest in our general partner, and upon closing of a merger with WMB, would own limited partner interest in ETE. We are unable to predict whether we will be successful in acquiring WMB and the ultimate terms of such acquisition. If we enter into an agreement with WMB with respect to a transaction, the closing of the transaction will be subject to certain closing conditions, including WMB stockholder approval and regulatory approvals, and there can be no assurance that the closing conditions will be satisfied. Regency Merger On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency continuing as the surviving entity (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP common units. ETP issued 172.2 million ETP common units to Regency unitholders, including 15.5 million units issued to subsidiaries of ETP. The 1.9 million outstanding Regency series A preferred units were converted into corresponding new ETP Series A Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE 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. Sunoco LP In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million . Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued $41 million of Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015. In July 2015, Sunoco LP acquired 100% of Susser from ETP in a transaction valued at $1.93 billion . Sunoco LP paid approximately $967 million in cash and issued 22 million Sunoco LP common units, valued at approximately $967 million , to ETP. In addition, there will be an exchange for 11 million Sunoco LP units owned by Susser for another 11 million new Sunoco LP units to a subsidiary of ETP. In July 2015, ETE entered into an exchange and repurchase agreement with ETP, pursuant to which ETE would acquire 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, in exchange for the repurchase of 21 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years , which would terminate upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE agreed to provide ETP a $35 million annual IDR subsidy for two years. Following this transaction, Sunoco LP will no longer be consolidated for accounting purposes by ETP. This transaction is expected to close in August 2015. Bakken Pipeline 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. These IDR subsidies, 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 six months ended June 30, 2014 includes the results of operations for a marketing business that was sold effective April 1, 2014.

Cash And Cash Equivalents

Cash And Cash Equivalents	6 Months Ended
	Jun. 30, 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: Six Months Ended 2015 2014 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 693 $ 339 Accrued advances to unconsolidated affiliates — 175 Net gains from subsidiary common unit issuances 50 560 NON-CASH FINANCING ACTIVITIES: Subsidiary issuances of common units in connection with PVR and Hoover acquisitions $ — $ 4,015 Long-term debt assumed in PVR acquisition — 1,887

Inventories (Notes)

Inventories (Notes)	6 Months Ended
	Jun. 30, 2015
Inventory, Net [Abstract]
Inventories	INVENTORIES Inventories consisted of the following: June 30, December 31, Natural gas and NGLs $ 425 $ 392 Crude oil 599 364 Refined products 446 392 Other 388 319 Total inventories $ 1,858 $ 1,467 We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
Fair Value Measurements [Abstract]
Fair Value Measurements	FAIR VALUE MEASURES 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. As of December 31, 2014, derivatives related to the Regency Preferred Units were valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. Also on April 30, 2015, in connection with the Regency Merger, the Regency Series A Preferred Units were converted into the right to receive a preferred unit representing a limited partner interest in ETP. During the six months ended June 30, 2015 , no transfers were made between any levels within the fair value hierarchy. Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of June 30, 2015 was $35.18 billion and $34.81 billion , respectively. As of December 31, 2014 , the aggregate fair value and carrying amount of our consolidated debt obligations was $31.68 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 June 30, 2015 and December 31, 2014 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 1 $ — $ 1 $ — Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 7 7 — — Swing Swaps IFERC 2 — 2 — Fixed Swaps/Futures 213 213 — — Forward Physical Swaps 2 — 2 — Power: Forwards 4 — 4 — Futures 3 3 — — Options — Calls 5 5 — — Natural Gas Liquids – Forwards/Swaps 31 31 — — Refined Products — Futures 6 6 — — Total commodity derivatives 273 265 8 — Total assets $ 274 $ 265 $ 9 $ — Liabilities: Interest rate derivatives $ (105 ) $ — $ (105 ) $ — Embedded derivatives in the ETP Preferred Units (12 ) — — (12 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (7 ) (7 ) — — Swing Swaps IFERC (2 ) (1 ) (1 ) — Fixed Swaps/Futures (189 ) (189 ) — — Forward Physical Swaps (1 ) — (1 ) — Power: Forwards (3 ) — (3 ) — Futures (7 ) (7 ) — — Options — Puts (4 ) (4 ) — — Natural Gas Liquids – Forwards/Swaps (29 ) (29 ) — — Refined Products — Futures (6 ) (6 ) — — Total commodity derivatives (248 ) (243 ) (5 ) — Total liabilities $ (365 ) $ (243 ) $ (110 ) $ (12 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 3 $ — $ 3 $ — Commodity derivatives: Condensate — Forward Swaps 36 — 36 — Natural Gas: Basis Swaps IFERC/NYMEX 19 19 — — Swing Swaps IFERC 26 1 25 — Fixed Swaps/Futures 566 541 25 — Forward Physical Contracts 1 — 1 — Power: Forwards 3 — 3 — Futures 4 4 — — Natural Gas Liquids — Forwards/Swaps 69 46 23 — Refined Products — Futures 21 21 — — Total commodity derivatives 745 632 113 — Total assets $ 748 $ 632 $ 116 $ — Liabilities: Interest rate derivatives $ (155 ) $ — $ (155 ) $ — Embedded derivatives in the 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 six months ended June 30, 2015 . Balance, December 31, 2014 $ (16 ) Net unrealized gains included in other income (expense) 4 Balance, June 30, 2015 $ (12 )

Net Income per Limited Partner

Net Income per Limited Partner Unit	6 Months Ended
	Jun. 30, 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 Six Months Ended 2015 2014 2015 2014 Income from continuing operations $ 772 $ 458 $ 993 $ 882 Less: Income from continuing operations attributable to noncontrolling interest 474 298 411 557 Income from continuing operations, net of noncontrolling interest 298 160 582 325 Less: General Partner’s interest in income from continuing operations — 1 1 1 Less: Class D Unitholder’s interest in income from continuing operations — — 1 1 Income from continuing operations available to Limited Partners $ 298 $ 159 $ 580 $ 323 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 1,076.0 1,087.3 1,077.2 1,101.2 Basic income from continuing operations per Limited Partner unit $ 0.28 $ 0.15 $ 0.54 $ 0.29 Basic income from discontinued operations per Limited Partner unit $ 0.00 $ 0.00 $ 0.00 $ 0.01 Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 298 $ 159 $ 580 $ 323 Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder 1 — 1 (1 ) Diluted income from continuing operations available to Limited Partners $ 299 $ 159 $ 581 $ 322 Weighted average limited partner units 1,076.0 1,087.3 1,077.2 1,101.2 Dilutive effect of unconverted unit awards 1.6 1.8 1.8 1.8 Weighted average limited partner units, assuming dilutive effect of unvested unit awards 1,077.6 1,089.1 1,079.0 1,103.0 Diluted income from continuing operations per Limited Partner unit $ 0.28 $ 0.15 $ 0.54 $ 0.29 Diluted income from discontinued operations per Limited Partner unit $ 0.00 $ 0.00 $ 0.00 $ 0.01

Debt Obligations

Debt Obligations	6 Months Ended
	Jun. 30, 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% . For the $1.4 billion aggregate principal amount under the Senior Secured Term Loan B Agreement of the ETE Term Loan Facility, 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 2.50% and the applicable margin for base rate loans is 1.50% . Revolving Credit Facility The Parent Company’s revolving credit facility has a capacity of $1.5 billion . As of June 30, 2015 , there were $230 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $1.27 billion . Senior Notes In May, ETE issued $1 billion aggregate principal amount of its 5.5% senior notes maturing 2027. 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 June 2015, ETP issued $650 million aggregate principal amount of 2.50% senior notes due June 2018, $350 million aggregate principal amount of 4.15% senior notes due October 2020, $1.0 billion aggregate principal amount of 4.75% senior notes due January 2026 and $1.0 billion aggregate principal amount of 6.125% senior notes due December 2045. ETP used the net proceeds of $2.98 billion from the offering to pay outstanding borrowings under the ETP Credit Facility to fund growth capital expenditures and for general partnership purposes. In March 2015, ETP issued $1.0 billion aggregate principal amount of 4.05% senior notes due March 2025, $500 million aggregate principal amount of 4.90% senior notes due March 2035, and $1.0 billion aggregate principal amount of 5.15% senior notes due March 2045. ETP used the $2.48 billion net proceeds from the offering to pay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes. Regency Senior Notes Panhandle previously agreed to fully and unconditionally guarantee (the “Panhandle Guarantee”) all of the payment obligations of Regency and Regency Energy Finance Corp. under their $600 million in aggregate principal amount of 4.50% senior notes due November 2023. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released. On June 1, 2015, Regency redeemed all of the outstanding $499 million aggregate principal amount of its 8.375% senior notes due June 2019. In July 2015, Regency issued notices of redemption to the holders of the $390 million aggregate principal amount of its 8.375% senior notes due June 2020, with a redemption date of August 13, 2015, and the $400 million aggregate principal amount of its 6.50% senior notes due May 2021, with a redemption date of August 10, 2015. Sunoco LP Senior Notes In April 2015, Sunoco LP issued $800 million aggregate principal amount of 6.375% senior notes due April 2023. The net proceeds from the offering were used to fund the cash portion of the dropdown of Sunoco, LLC interests and to repay outstanding balances under the Sunoco LP revolving credit facility. In July 2015, Sunoco LP issued $600 million aggregate principal amount of 5.5% senior notes due August 2020. The net proceeds from the offering were used to fund a portion of the cash consideration for Sunoco LP’s acquisition of Susser. 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 June 30, 2015 , the ETP Credit Facility had no outstanding borrowings. Regency Credit Facility The Regency Credit Facility allowed for borrowings of $2.5 billion and would have expired on November 25, 2019 . 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 June 30, 2015 , the Sunoco Logistics Credit Facility had $550 million of outstanding borrowings. Sunoco LP Credit Facility Sunoco LP maintains a $1.5 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 June 30, 2015 , the Sunoco LP Credit Facility had $725 million of outst anding borrowings. 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 June 30, 2015 .

Redeemable Noncontrolling Inter

Redeemable Noncontrolling Interest (Notes)	6 Months Ended
	Jun. 30, 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	6 Months Ended
	Jun. 30, 2015
Partners' Capital Notes [Abstract]
Equity	EQUITY ETE Common Unit Activity The changes in ETE common units during the six months ended June 30, 2015 were as follows: Number of Units Outstanding at December 31, 2014 1,077.5 Conversion of Class D Units to ETE common units 0.9 Repurchase of units under buyback program (8.6 ) Outstanding at June 30, 2015 1,069.8 On May 28, 2015, ETE announced that the board of directors of its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “Unit Split”). The Unit Split was completed on July 27, 2015. The Unit Split was effected by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015. During the three months ended June 30, 2015, ETE repurchased approximately $294 million of ETE common units under its $2.0 billion buyback program. Subsidiary Common Unit Transactions The Parent Company accounts for the difference between the carrying amount of its investments in ETP and the underlying book value arising from the issuance or redemption of units by ETP and Regency (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions during the six months ended June 30, 2015 , we recognized increases in partners’ capital of $50 million . ETP Common Unit Transactions During the six months ended June 30, 2015 , ETP received proceeds of $569 million , net of commissions of $6 million , from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes. As of June 30, 2015 , approximately $832 million of ETP common units remained available to be issued under an equity distribution agreement. During the six months ended June 30, 2015 , distributions of $155 million were reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of 2.8 million ETP common units. As of June 30, 2015 , a total of 4.5 million ETP common units remain available to be issued under the existing registration statement in connection with ETP’s Distribution Reinvestment Plan. 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. These IDR subsidies, 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.” Regency Common Unit Transactions For the six months ended June 30, 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 June 30, 2015 , and the equity distribution agreement terminated as a result of the merger with ETP in April 2015. Sunoco Logistics Common Unit Transactions 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 six months ended June 30, 2015 , Sunoco Logistics received proceeds of $385 million , net of commissions of $4 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. Sunoco LP Common Unit Transactions In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million . The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility. Parent Company Quarterly Distributions of Available Cash Following are distributions declared and/or paid by us subsequent to December 31, 2014 (on a post-split basis): Quarter Ended Record Date Payment Date Rate December 31, 2014 February 6, 2015 February 19, 2015 $ 0.2250 March 31, 2015 May 8, 2015 May 19, 2015 0.2450 June 30, 2015 August 6, 2015 August 19, 2015 0.2650 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 December 31, 2014 February 6, 2015 February 13, 2015 $ 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 ETE 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) $ 56 2016 137 2017 128 2018 105 2019 95 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 December 31, 2014 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 quarters ended March 31, 2015 or subsequent quarters 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 December 31, 2014 February 9, 2015 February 13, 2015 $ 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380 Sunoco LP 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 December 31, 2014 February 17, 2015 February 27, 2015 $ 0.6000 March 31, 2015 May 19, 2015 May 29, 2015 0.6450 June 30, 2015 August 18, 2015 August 28, 2015 0.6934 Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: June 30, December 31, 2014 Available-for-sale securities $ 3 $ 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 (14 ) (56 ) Amounts attributable to noncontrolling interest 12 51 Total AOCI, net of tax $ (2 ) $ (5 )

Income Taxes (Notes)

Income Taxes (Notes)	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES For the three and six months ended June 30, 2015 , the Partnership’s effective income tax rate decreased from the prior year primarily due to lower earnings among the Partnership’s consolidated corporate subsidiaries. In addition, the three and six months ended June 30, 2015 also reflect a benefit of $22 million related to the exclusion of a portion of the dividend income received by certain of our consolidated corporate subsidiaries. For the three and six months ended June 30, 2015 , the Partnership’s income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015. For the three and six months ended June 30, 2014 , the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $87 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes. During the three months ended June 30, 2015 , Sunoco, Inc. filed a petition for refund with the United States Court of Federal Claims in response to a notice of disallowance denying previously filed refund claims related to certain government incentive payments. Also, during the same period, Sunoco, Inc. filed amended state income tax returns in material jurisdictions based on the Federal claim. The state refund claim is $87 million ( $57 million after Federal taxes). Consistent with treatment of Federal claims, Sunoco, Inc. has established a reserve for the full amount of the increase due to the uncertain nature of the claims. On July 23, 2015, we reached a final settlement with the Internal Revenue Service (“IRS”) with regards to the IRS examination of Southern Union’s tax years 2004 through 2009. For the 2006 tax year, the IRS had challenged $545 million of the $690 million deferred gain associated with the like kind exchange involving certain assets of Southern Union’s distribution operations and gathering and processing operations. The terms of the settlement specify that our position with regards to the deferred gain on the like kind exchange was materially correct and as a result, we will receive refunds totaling approximately $6 million for the periods under examination.

Regulatory Matters, Commitments

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	6 Months Ended
	Jun. 30, 2015
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million , representing the amount of the judgment, plus interest, in a case tried in 2011. On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011. FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs. Contingent Residual Support Agreement — AmeriGas In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchasers. Guarantee of Collection Panhandle previously guaranteed the collections of the payment of $600 million of Regency 4.50% senior notes due 2023. In May 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under Panhandle’s guarantee have been released. On April 30, 2015, in connection with the Regency Merger, ETP entered into various supplemental indentures pursuant to which ETP has agreed to fully and unconditionally guarantee all payment obligations of Regency for all of its outstanding senior notes. NGL Pipeline Regulation 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 the 2011 settlement agreement with its shippers. On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015. On June 22, 2015, Transwestern filed a settlement with the Commission which resolved, or provided for the resolution of all issues set for hearing in the case. The settlement is subject to Commission approval. FGT Rate Case On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective no earlier than May 1, 2015, subject to refund. Currently a procedural schedule is set with a hearing scheduled in early 2016. 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 Six Months Ended 2015 2014 2015 2014 Rental expense (1) $ 54 $ 27 $ 106 $ 59 Less: Sublease rental income (4 ) (10 ) (12 ) (18 ) Rental expense, net $ 50 $ 17 $ 94 $ 41 (1) Includes contingent rentals totaling $6 million and $6 million for the three months ended June 30, 2015 and 2014 and $10 million and $9 million for the six months ended June 30, 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. Regency Merger Litigation Following the January 26, 2015 announcement of the definitive merger agreement with Regency, purported Regency unitholders filed lawsuits in state and federal courts in Dallas, Texas and Delaware state court asserting claims relating to the proposed transaction. On February 3, 2015, William Engel and Enno Seago, purported Regency unitholders, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 162nd Judicial District Court of Dallas County, Texas (the “Engel Lawsuit”). The lawsuit names as defendants the Regency General Partner, the members of the Regency General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, Regency. The Engel Lawsuit alleges that (1) the Regency General Partner’s directors breached duties to Regency and the Regency’s unitholders by employing a conflicted and unfair process and failing to maximize the merger consideration; (2) the Regency General Partner’s directors breached the implied covenant of good faith and fair dealing by engaging in a flawed merger process; and (3) the non-director defendants aided and abetted in these claimed breaches. The plaintiffs seek an injunction preventing the defendants from closing the proposed transaction or an order rescinding the transaction if it has already been completed. The plaintiffs also seek money damages and court costs, including attorney’s fees. On February 9, 2015, Stuart Yeager, a purported Regency unitholder, filed a class action petition on behalf of the Regency’s common unitholders and a derivative suit on behalf of Regency in the 134th Judicial District Court of Dallas County, Texas (the “Yeager Lawsuit”). The allegations, claims, and relief sought in the Yeager Lawsuit are nearly identical to those in the Engel Lawsuit. On February 10, 2015, Lucien Coggia a purported Regency unitholder, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 192nd Judicial District Court of Dallas County, Texas (the “Coggia Lawsuit”). The allegations, claims, and relief sought in the Coggia Lawsuit are nearly identical to those in the Engel Lawsuit. On February 3, 2015, Linda Blankman, a purported Regency unitholder, filed a class action complaint on behalf of the Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Blankman Lawsuit”). The allegations and claims in the Blankman Lawsuit are similar to those in the Engel Lawsuit. However, the Blankman Lawsuit does not allege any derivative claims and includes Regency as a defendant rather than a nominal party. The lawsuit also omits one of the Regency General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the Regency General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of Regency, failing to properly value Regency, and ignoring conflicts of interest. The plaintiff also asserts a claim against the non-director defendants for aiding and abetting the directors’ alleged breach of fiduciary duty. The Blankman Lawsuit seeks the same relief that the plaintiffs seek in the Engel Lawsuit. On February 6, 2015, Edwin Bazini, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Bazini Lawsuit”). The allegations, claims, and relief sought in the Bazini Lawsuit are nearly identical to those in the Blankman Lawsuit. On March 27, 2015, Plaintiff Bazini filed an amended complaint asserting additional claims under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934. On February 11, 2015, Mark Hinnau, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Hinnau Lawsuit”). The allegations, claims, and relief sought in the Hinnau Lawsuit are nearly identical to those in the Blankman Lawsuit. On February 11, 2015, Stephen Weaver, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Weaver Lawsuit”). The allegations, claims, and relief sought in the Weaver Lawsuit are nearly identical to those in the Blankman Lawsuit. On February 11, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Dieckman Lawsuit are similar to those in the Blankman Lawsuit, except that the Dieckman Lawsuit does not assert an aiding and abetting claim. On February 13, 2015, Irwin Berlin, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Berlin Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit. On March 13, 2015, the Court in the 95th Judicial District Court of Dallas County, Texas transferred and consolidated the Yeager and Coggia Lawsuits into the Engel Lawsuit and captioned the consolidated lawsuit as Engel v. Regency GP, LP, et al . (the “Consolidated State Lawsuit”). On March 30, 2015, Leonard Cooperman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Cooperman Lawsuit”). The allegations, claims, and relief sought in the Cooperman Lawsuit are similar to those in the Blankman Lawsuit. On March 31, 2015, the Court in United States District Court for the Northern District of Texas consolidated the Blankman, Bazini, Hinnau, Weaver, Dieckman, and Berlin Lawsuits into a consolidated lawsuit captioned Bazini v. Bradley, et al . (the “Consolidated Federal Lawsuit”). On April 1, 2015, plaintiffs in the Consolidated Federal Lawsuit filed an Emergency Motion to Expedite Discovery. On April 9, 2015, by order of the Court, the parties submitted a joint submission wherein defendants opposed plaintiffs’ request to expedite discovery. On April 17, 2015, the Court denied plaintiffs’ motion to expedite discovery. On June 10, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware (the “Dieckman DE Lawsuit”). The lawsuit alleges that the transaction did not comply with the Regency partnership agreement because the Conflicts Committee was not properly formed. Each of these lawsuits is at a preliminary stage. ETP cannot predict the outcome of these or any other lawsuits that might be filed, nor can we predict the amount of time and expense that will be required to resolve these lawsuits. ETP and the other defendants named in the lawsuits intend to defend vigorously against these and any other actions. 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 June 30, 2015 , Sunoco, Inc. is a defendant in six cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action, and one case by the City of Breaux Bridge in the USDC Western District of Louisiana. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims. Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. 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 June 30, 2015 and December 31, 2014 , accruals of approximately $38 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 June 30, 2015 or December 31, 2014 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Attorney General of the Commonwealth of Massachusetts v. New England Gas Company. On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling approximately $19 million , that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50% , level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses. Environmental Matters Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position. Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs. Environmental Remediation Our subsidiaries are responsible for environmental remediation at certain sites, including the following: • Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. • Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. • Currently operating Sunoco, Inc. retail sites. • Legacy sites related to Sunoco, Inc., that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites. • Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it ha s been identified as a potentially responsible party (“PRP”). As of June 30, 2015 , Sunoco, Inc. had been named as a PRP at approximately 52 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets. The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. June 30, December 31, 2014 Current $ 49 $ 41 Non-current 334 360 Total environmental liabilities $ 383 $ 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 June 30, 2015 and 2014 , Sunoco, Inc. recorded $11 million and $9 million , respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2015 and 2014 , Sunoco, Inc. recorded $18 million and $17 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.

Derivative Assets And Liabiliti

Derivative Assets And Liabilities	6 Months Ended
	Jun. 30, 2015
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Derivative Assets And Liabilities	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 our price risk management activities. 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 statements 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 our outstanding commodity-related derivatives: June 30, 2015 December 31, 2014 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (1,075,000 ) 2015-2016 (232,500 ) 2015 Basis Swaps IFERC/NYMEX (1) (4,527,500 ) 2015-2016 (13,907,500 ) 2015-2016 Options – Calls 5,000,000 2015 5,000,000 2015 Power (Megawatt): Forwards 373,357 2015-2016 288,775 2015 Futures 436,789 2015-2016 (156,000 ) 2015 Options — Puts (581,328 ) 2015 (72,000 ) 2015 Options — Calls (1,428,154 ) 2015 198,556 2015 (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX 10,327,500 2015-2016 57,500 2015 Swing Swaps IFERC 23,335,000 2015-2016 46,150,000 2015 Fixed Swaps/Futures (11,577,500 ) 2015-2016 (34,304,000 ) 2015-2016 Forward Physical Contracts 4,424,847 2015 (9,116,777 ) 2015 Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps (3,730,800 ) 2015-2016 (4,417,400 ) 2015-2016 Refined Products (Bbls) — Futures (1,195,000 ) 2015-2016 13,745,755 2015 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (37,555,000 ) 2016 (39,287,500 ) 2015 Fixed Swaps/Futures (37,555,000 ) 2016 (39,287,500 ) 2015 Hedged Item — Inventory 37,555,000 2016 39,287,500 2015 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. Regency previously had swap contracts that settled against certain NGLs, condensate and natural gas market prices. In April 2015, in connection with the Regency Merger, Regency settled all outstanding swap contracts and received net proceeds of $56 million . Interest Rate Risk We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and 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) June 30, December 31, 2014 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 3.25% and receive a floating rate 200 300 ETP December 2018 Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53% 1,200 — ETP March 2019 Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.42% 300 — ETP February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% — 200 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward starting swaps have 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, motor fuel distributors, municipalities, utilities and midstream companies. ETP’s overall exposure may be affected positively or negatively by macroeconomic factors 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. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income. Derivative Summary The following table provides a summary of our derivative assets and liabilities: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives June 30, 2015 December 31, 2014 June 30, 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) $ 265 $ 617 $ (245 ) $ (577 ) Commodity derivatives 18 107 (16 ) (23 ) Interest rate derivatives 1 3 (105 ) (155 ) Embedded derivatives preferred units — — (12 ) (16 ) 284 727 (378 ) (771 ) Total derivatives $ 287 $ 770 $ (378 ) $ (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 June 30, 2015 December 31, 2014 June 30, 2015 December 31, 2014 Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) $ 18 $ 23 $ (16 ) $ (23 ) Broker cleared derivative contracts Other current assets 264 674 (248 ) (574 ) 282 697 (264 ) (597 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (12 ) (19 ) 12 19 Payments on margin deposit Other current assets 16 5 (9 ) (22 ) 4 (14 ) 3 (3 ) Net derivatives with offsetting agreements 286 683 (261 ) (600 ) Derivatives without offsetting agreements 1 87 (117 ) (171 ) Total derivatives $ 287 $ 770 $ (378 ) $ (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 Six Months Ended 2015 2014 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ (2 ) $ 1 $ (6 ) Total $ — $ (2 ) $ 1 $ (6 ) Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Three Months Ended Six Months Ended 2015 2014 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ (2 ) $ — $ (6 ) Total $ — $ (2 ) $ — $ (6 ) Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Three Months Ended Six Months Ended 2015 2014 2015 2014 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 11 $ — $ 8 $ (6 ) Total $ 11 $ — $ 8 $ (6 ) Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Three Months Ended Six Months Ended 2015 2014 2015 2014 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (6 ) $ (5 ) $ (8 ) $ 2 Commodity derivatives – Non-trading Cost of products sold (40 ) (37 ) (48 ) (43 ) Interest rate derivatives Gains (losses) on interest rate derivatives 127 (46 ) 50 (48 ) Embedded derivatives Other income (expense) 2 (9 ) 4 (10 ) Total $ 83 $ (97 ) $ (2 ) $ (99 )

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 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 $130 million and $206 million during the three and six months ended June 30, 2015, respectively, and $362 million and $690 million during the three and six months ended June 30, 2014, respectively.

Other Information

Other Information	6 Months Ended
	Jun. 30, 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: June 30, December 31, 2014 Deposits paid to vendors $ 36 $ 65 Deferred income taxes — 14 Income taxes receivable 151 17 Prepaid expenses and other 195 205 Total other current assets $ 382 $ 301 Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: June 30, December 31, 2014 Interest payable $ 468 $ 440 Customer advances and deposits 100 103 Accrued capital expenditures 608 673 Accrued wages and benefits 156 233 Taxes payable other than income taxes 302 236 Income taxes payable 4 54 Deferred income taxes 99 99 Other 321 363 Total accrued and other current liabilities $ 2,058 $ 2,201

Reportable Segments

Reportable Segments	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Reportable Segments	REPORTABLE SEGMENTS Subsequent to ETP’s acquisition of Regency, our financial statements reflect the following reportable business segments: • Investment in ETP, including the consolidated operations of ETP; • 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. ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented. 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. The following tables present financial information by segment: Three Months Ended Six Months Ended 2015 2014 2015 2014 Segment Adjusted EBITDA: Investment in ETP $ 1,488 $ 1,393 $ 2,854 $ 2,731 Investment in Lake Charles LNG 49 47 98 95 Corporate and Other (25 ) (29 ) (48 ) (55 ) Adjustments and Eliminations — 29 — 44 Total 1,512 1,440 2,904 2,815 Depreciation, depletion and amortization (514 ) (450 ) (1,007 ) (823 ) Interest expense, net of interest capitalized (408 ) (344 ) (779 ) (659 ) Gain on sale of AmeriGas common units — 93 — 163 Gains (losses) on interest rate derivatives 127 (46 ) 50 (48 ) Non-cash unit-based compensation expense (25 ) (20 ) (48 ) (40 ) Unrealized losses on commodity risk management activities (44 ) (10 ) (119 ) (43 ) Inventory valuation adjustments 184 20 150 34 Equity in earnings of unconsolidated affiliates 117 77 174 181 Adjusted EBITDA related to unconsolidated affiliates (215 ) (190 ) (361 ) (400 ) Adjusted EBITDA related to discontinued operations — — — (27 ) Other, net (18 ) (42 ) (15 ) (56 ) Income from continuing operations before income tax expense $ 716 $ 528 $ 949 $ 1,097 June 30, December 31, 2014 Assets: Investment in ETP $ 67,551 $ 62,674 Investment in Lake Charles LNG 1,289 1,210 Corporate and Other 666 1,153 Adjustments and Eliminations (361 ) (568 ) Total assets $ 69,145 $ 64,469 Three Months Ended Six Months Ended 2015 2014 2015 2014 Revenues: Investment in ETP: Revenues from external customers $ 11,540 $ 14,088 $ 21,866 $ 27,115 Intersegment revenues — — — — 11,540 14,088 21,866 27,115 Investment in Lake Charles LNG: Revenues from external customers 54 53 108 107 Adjustments and Eliminations — 2 — 1 Total revenues $ 11,594 $ 14,143 $ 21,974 $ 27,223 The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Lake Charles LNG. Investment in ETP Three Months Ended Six Months Ended 2015 2014 2015 2014 Intrastate Transportation and Storage $ 486 $ 667 $ 1,027 $ 1,512 Interstate Transportation and Storage 239 245 510 540 Midstream 771 1,297 1,524 2,349 Liquids Transportation and Services 779 867 1,587 1,659 Investment in Sunoco Logistics 3,121 4,766 5,647 9,218 Retail Marketing 5,557 5,568 10,339 10,576 All Other 587 678 1,232 1,261 Total revenues 11,540 14,088 21,866 27,115 Less: Intersegment revenues — — — — Revenues from external customers $ 11,540 $ 14,088 $ 21,866 $ 27,115 Investment in Lake Charles LNG Lake Charles LNG’s revenues of $54 million and $108 million for the three and six months ended June 30, 2015, respectively, and $53 million and $107 million for the six months ended June 30, 2014, respectively, were related to LNG terminalling.

Supplemental Financial Statemen

Supplemental Financial Statement Information	6 Months Ended
	Jun. 30, 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) June 30, December 31, 2014 ASSETS Current assets: Cash and cash equivalents $ 1 $ 2 Accounts receivable from related companies 21 14 Other current assets 1 1 Total current assets 23 17 Property, plant and equipment, net 7 — Advances to and investments in unconsolidated affiliates 6,406 5,390 Intangible assets, net 8 10 Goodwill 9 9 Other non-current assets, net 52 46 Total assets $ 6,505 $ 5,472 LIABILITIES AND PARTNERS’ CAPITAL Current liabilities: Accounts payable to related companies $ 84 $ 11 Interest payable 71 58 Accrued and other current liabilities 2 3 Total current liabilities 157 72 Long-term debt, less current maturities 5,737 4,680 Note payable to affiliate 109 54 Other non-current liabilities 1 2 Commitments and contingencies Partners’ capital: General Partner (1 ) (1 ) Limited Partners: Common Unitholders 484 648 Class D Units 20 22 Accumulated other comprehensive loss (2 ) (5 ) Total partners’ capital 501 664 Total liabilities and partners’ capital $ 6,505 $ 5,472 STATEMENTS OF OPERATIONS (unaudited) Three Months Ended Six Months Ended 2015 2014 2015 2014 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES (1) $ (29 ) $ (32 ) $ (57 ) $ (63 ) OTHER INCOME (EXPENSE): Interest expense, net of interest capitalized (72 ) (50 ) (133 ) (90 ) Equity in earnings of unconsolidated affiliates 398 248 771 487 Other, net — (2 ) 1 (2 ) INCOME BEFORE INCOME TAXES 297 164 582 332 Income tax benefit (1 ) — — — NET INCOME 298 164 582 332 General Partner’s interest in net income — 1 1 1 Class D Unitholder’s interest in net income — — 1 1 Limited Partners’ interest in net income $ 298 $ 163 $ 580 $ 330 (1) Includes management fees paid by ETE to ETP. STATEMENTS OF CASH FLOWS (unaudited) Six Months Ended 2015 2014 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 475 $ 497 CASH FLOWS FROM INVESTING ACTIVITIES: Cash paid for Bakken Pipeline Transaction (817 ) — Contributions to unconsolidated affiliate — (8 ) Capital expenditures (7 ) — Purchase of additional interest in Regency — (400 ) Cash received from affiliate 106 — Net cash used in investing activities (718 ) (408 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings 2,972 2,390 Principal payments on debt (1,915 ) (1,051 ) Distributions to partners (509 ) (391 ) Units repurchased under buyback program (294 ) (1,000 ) Debt issuance costs (12 ) (14 ) Net cash provided by (used in) financing activities 242 (66 ) INCREASE IN CASH AND CASH EQUIVALENTS (1 ) 23 CASH AND CASH EQUIVALENTS, beginning of period 2 8 CASH AND CASH EQUIVALENTS, end of period $ 1 $ 31

Operations And Organization Acc

Operations And Organization Accounting policy (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Consolidation, Subsidiary Stock Issuances, Policy [Policy Text Block]	Subsidiary Common Unit Transactions 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.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates 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.
New Accounting Pronouncements, Policy [Policy Text Block]	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.
Excise Tax, Policy [Policy Text Block]	Excise Taxes The Partnership records the collection of taxes to be remitted to government authorities on a net basis except for 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 the retail marketing operations were $762 million and $573 million for the three months ended June 30, 2015 and 2014 , respectively, and $1.50 billion and $1.10 billion for the six months ended June 30, 2015 and 2014 , respectively.

Cash And Cash Equivalents (Tabl

Cash And Cash Equivalents (Tables)	6 Months Ended
	Jun. 30, 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: Six Months Ended 2015 2014 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 693 $ 339 Accrued advances to unconsolidated affiliates — 175 Net gains from subsidiary common unit issuances 50 560 NON-CASH FINANCING ACTIVITIES: Subsidiary issuances of common units in connection with PVR and Hoover acquisitions $ — $ 4,015 Long-term debt assumed in PVR acquisition — 1,887

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Jun. 30, 2015
Inventory, Net [Abstract]
Schedule Of Inventory	Inventories consisted of the following: June 30, December 31, Natural gas and NGLs $ 425 $ 392 Crude oil 599 364 Refined products 446 392 Other 388 319 Total inventories $ 1,858 $ 1,467

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 2015 and December 31, 2014 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 1 $ — $ 1 $ — Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 7 7 — — Swing Swaps IFERC 2 — 2 — Fixed Swaps/Futures 213 213 — — Forward Physical Swaps 2 — 2 — Power: Forwards 4 — 4 — Futures 3 3 — — Options — Calls 5 5 — — Natural Gas Liquids – Forwards/Swaps 31 31 — — Refined Products — Futures 6 6 — — Total commodity derivatives 273 265 8 — Total assets $ 274 $ 265 $ 9 $ — Liabilities: Interest rate derivatives $ (105 ) $ — $ (105 ) $ — Embedded derivatives in the ETP Preferred Units (12 ) — — (12 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (7 ) (7 ) — — Swing Swaps IFERC (2 ) (1 ) (1 ) — Fixed Swaps/Futures (189 ) (189 ) — — Forward Physical Swaps (1 ) — (1 ) — Power: Forwards (3 ) — (3 ) — Futures (7 ) (7 ) — — Options — Puts (4 ) (4 ) — — Natural Gas Liquids – Forwards/Swaps (29 ) (29 ) — — Refined Products — Futures (6 ) (6 ) — — Total commodity derivatives (248 ) (243 ) (5 ) — Total liabilities $ (365 ) $ (243 ) $ (110 ) $ (12 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 3 $ — $ 3 $ — Commodity derivatives: Condensate — Forward Swaps 36 — 36 — Natural Gas: Basis Swaps IFERC/NYMEX 19 19 — — Swing Swaps IFERC 26 1 25 — Fixed Swaps/Futures 566 541 25 — Forward Physical Contracts 1 — 1 — Power: Forwards 3 — 3 — Futures 4 4 — — Natural Gas Liquids — Forwards/Swaps 69 46 23 — Refined Products — Futures 21 21 — — Total commodity derivatives 745 632 113 — Total assets $ 748 $ 632 $ 116 $ — Liabilities: Interest rate derivatives $ (155 ) $ — $ (155 ) $ — Embedded derivatives in the 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 six months ended June 30, 2015 . Balance, December 31, 2014 $ (16 ) Net unrealized gains included in other income (expense) 4 Balance, June 30, 2015 $ (12 )

Net Income per Limited Partne27

Net Income per Limited Partner Unit (Tables)	6 Months Ended
	Jun. 30, 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 Six Months Ended 2015 2014 2015 2014 Income from continuing operations $ 772 $ 458 $ 993 $ 882 Less: Income from continuing operations attributable to noncontrolling interest 474 298 411 557 Income from continuing operations, net of noncontrolling interest 298 160 582 325 Less: General Partner’s interest in income from continuing operations — 1 1 1 Less: Class D Unitholder’s interest in income from continuing operations — — 1 1 Income from continuing operations available to Limited Partners $ 298 $ 159 $ 580 $ 323 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 1,076.0 1,087.3 1,077.2 1,101.2 Basic income from continuing operations per Limited Partner unit $ 0.28 $ 0.15 $ 0.54 $ 0.29 Basic income from discontinued operations per Limited Partner unit $ 0.00 $ 0.00 $ 0.00 $ 0.01 Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 298 $ 159 $ 580 $ 323 Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder 1 — 1 (1 ) Diluted income from continuing operations available to Limited Partners $ 299 $ 159 $ 581 $ 322 Weighted average limited partner units 1,076.0 1,087.3 1,077.2 1,101.2 Dilutive effect of unconverted unit awards 1.6 1.8 1.8 1.8 Weighted average limited partner units, assuming dilutive effect of unvested unit awards 1,077.6 1,089.1 1,079.0 1,103.0 Diluted income from continuing operations per Limited Partner unit $ 0.28 $ 0.15 $ 0.54 $ 0.29 Diluted income from discontinued operations per Limited Partner unit $ 0.00 $ 0.00 $ 0.00 $ 0.01

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 30, 2015
Schedule of Net IDR Subsidies [Table Text Block]	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) $ 56 2016 137 2017 128 2018 105 2019 95
Change In ETE Common Units	The changes in ETE common units during the six months ended June 30, 2015 were as follows: Number of Units Outstanding at December 31, 2014 1,077.5 Conversion of Class D Units to ETE common units 0.9 Repurchase of units under buyback program (8.6 ) Outstanding at June 30, 2015 1,069.8
Accumulated Other Comprehensive Income	The following table presents the components of AOCI, net of tax: June 30, December 31, 2014 Available-for-sale securities $ 3 $ 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 (14 ) (56 ) Amounts attributable to noncontrolling interest 12 51 Total AOCI, net of tax $ (2 ) $ (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 (on a post-split basis): Quarter Ended Record Date Payment Date Rate December 31, 2014 February 6, 2015 February 19, 2015 $ 0.2250 March 31, 2015 May 8, 2015 May 19, 2015 0.2450 June 30, 2015 August 6, 2015 August 19, 2015 0.2650
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 December 31, 2014 February 6, 2015 February 13, 2015 $ 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350
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 December 31, 2014 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 December 31, 2014 February 9, 2015 February 13, 2015 $ 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380
Sunoco LP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	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 December 31, 2014 February 17, 2015 February 27, 2015 $ 0.6000 March 31, 2015 May 19, 2015 May 29, 2015 0.6450 June 30, 2015 August 18, 2015 August 28, 2015 0.6934

Regulatory Matters, Commitmen29

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)	6 Months Ended
	Jun. 30, 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 Six Months Ended 2015 2014 2015 2014 Rental expense (1) $ 54 $ 27 $ 106 $ 59 Less: Sublease rental income (4 ) (10 ) (12 ) (18 ) Rental expense, net $ 50 $ 17 $ 94 $ 41 (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. June 30, December 31, 2014 Current $ 49 $ 41 Non-current 334 360 Total environmental liabilities $ 383 $ 401

Derivative Assets And Liabili30

Derivative Assets And Liabilities (Tables)	6 Months Ended
	Jun. 30, 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) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Three Months Ended Six Months Ended 2015 2014 2015 2014 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (6 ) $ (5 ) $ (8 ) $ 2 Commodity derivatives – Non-trading Cost of products sold (40 ) (37 ) (48 ) (43 ) Interest rate derivatives Gains (losses) on interest rate derivatives 127 (46 ) 50 (48 ) Embedded derivatives Other income (expense) 2 (9 ) 4 (10 ) Total $ 83 $ (97 ) $ (2 ) $ (99 )
Outstanding Commodity-Related Derivatives	The following table details our outstanding commodity-related derivatives: June 30, 2015 December 31, 2014 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (1,075,000 ) 2015-2016 (232,500 ) 2015 Basis Swaps IFERC/NYMEX (1) (4,527,500 ) 2015-2016 (13,907,500 ) 2015-2016 Options – Calls 5,000,000 2015 5,000,000 2015 Power (Megawatt): Forwards 373,357 2015-2016 288,775 2015 Futures 436,789 2015-2016 (156,000 ) 2015 Options — Puts (581,328 ) 2015 (72,000 ) 2015 Options — Calls (1,428,154 ) 2015 198,556 2015 (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX 10,327,500 2015-2016 57,500 2015 Swing Swaps IFERC 23,335,000 2015-2016 46,150,000 2015 Fixed Swaps/Futures (11,577,500 ) 2015-2016 (34,304,000 ) 2015-2016 Forward Physical Contracts 4,424,847 2015 (9,116,777 ) 2015 Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps (3,730,800 ) 2015-2016 (4,417,400 ) 2015-2016 Refined Products (Bbls) — Futures (1,195,000 ) 2015-2016 13,745,755 2015 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (37,555,000 ) 2016 (39,287,500 ) 2015 Fixed Swaps/Futures (37,555,000 ) 2016 (39,287,500 ) 2015 Hedged Item — Inventory 37,555,000 2016 39,287,500 2015 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations
Interest Rate Swaps Outstanding	The following table summarizes our interest rate swaps outstanding none of which were designated as hedges for accounting purposes: Notional Amount Outstanding Entity Term Type (1) June 30, December 31, 2014 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 3.25% and receive a floating rate 200 300 ETP December 2018 Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53% 1,200 — ETP March 2019 Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.42% 300 — ETP February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% — 200 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward starting swaps have 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 June 30, 2015 December 31, 2014 June 30, 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) $ 265 $ 617 $ (245 ) $ (577 ) Commodity derivatives 18 107 (16 ) (23 ) Interest rate derivatives 1 3 (105 ) (155 ) Embedded derivatives preferred units — — (12 ) (16 ) 284 727 (378 ) (771 ) Total derivatives $ 287 $ 770 $ (378 ) $ (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 June 30, 2015 December 31, 2014 June 30, 2015 December 31, 2014 Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) $ 18 $ 23 $ (16 ) $ (23 ) Broker cleared derivative contracts Other current assets 264 674 (248 ) (574 ) 282 697 (264 ) (597 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (12 ) (19 ) 12 19 Payments on margin deposit Other current assets 16 5 (9 ) (22 ) 4 (14 ) 3 (3 ) Net derivatives with offsetting agreements 286 683 (261 ) (600 ) Derivatives without offsetting agreements 1 87 (117 ) (171 ) Total derivatives $ 287 $ 770 $ (378 ) $ (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 Six Months Ended 2015 2014 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ (2 ) $ 1 $ (6 ) Total $ — $ (2 ) $ 1 $ (6 )
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Three Months Ended Six Months Ended 2015 2014 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ (2 ) $ — $ (6 ) Total $ — $ (2 ) $ — $ (6 )
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Three Months Ended Six Months Ended 2015 2014 2015 2014 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 11 $ — $ 8 $ (6 ) Total $ 11 $ — $ 8 $ (6 )

Other Information (Tables)

Other Information (Tables)	6 Months Ended
	Jun. 30, 2015
Other Information [Abstract]
Other Current Assets	Other current assets consisted of the following: June 30, December 31, 2014 Deposits paid to vendors $ 36 $ 65 Deferred income taxes — 14 Income taxes receivable 151 17 Prepaid expenses and other 195 205 Total other current assets $ 382 $ 301
Accrued And Other Current Liabilities	Accrued and other current liabilities consisted of the following: June 30, December 31, 2014 Interest payable $ 468 $ 440 Customer advances and deposits 100 103 Accrued capital expenditures 608 673 Accrued wages and benefits 156 233 Taxes payable other than income taxes 302 236 Income taxes payable 4 54 Deferred income taxes 99 99 Other 321 363 Total accrued and other current liabilities $ 2,058 $ 2,201

Reportable Segments (Tables)

Reportable Segments (Tables)	6 Months Ended
	Jun. 30, 2015
Operating Segments [Member]
Financial Information By Segment	Three Months Ended Six Months Ended 2015 2014 2015 2014 Segment Adjusted EBITDA: Investment in ETP $ 1,488 $ 1,393 $ 2,854 $ 2,731 Investment in Lake Charles LNG 49 47 98 95 Corporate and Other (25 ) (29 ) (48 ) (55 ) Adjustments and Eliminations — 29 — 44 Total 1,512 1,440 2,904 2,815 Depreciation, depletion and amortization (514 ) (450 ) (1,007 ) (823 ) Interest expense, net of interest capitalized (408 ) (344 ) (779 ) (659 ) Gain on sale of AmeriGas common units — 93 — 163 Gains (losses) on interest rate derivatives 127 (46 ) 50 (48 ) Non-cash unit-based compensation expense (25 ) (20 ) (48 ) (40 ) Unrealized losses on commodity risk management activities (44 ) (10 ) (119 ) (43 ) Inventory valuation adjustments 184 20 150 34 Equity in earnings of unconsolidated affiliates 117 77 174 181 Adjusted EBITDA related to unconsolidated affiliates (215 ) (190 ) (361 ) (400 ) Adjusted EBITDA related to discontinued operations — — — (27 ) Other, net (18 ) (42 ) (15 ) (56 ) Income from continuing operations before income tax expense $ 716 $ 528 $ 949 $ 1,097
Assets Segments [Member]
Financial Information By Segment	June 30, December 31, 2014 Assets: Investment in ETP $ 67,551 $ 62,674 Investment in Lake Charles LNG 1,289 1,210 Corporate and Other 666 1,153 Adjustments and Eliminations (361 ) (568 ) Total assets $ 69,145 $ 64,469
Sales Revenue, Segment [Member]
Financial Information By Segment	Three Months Ended Six Months Ended 2015 2014 2015 2014 Revenues: Investment in ETP: Revenues from external customers $ 11,540 $ 14,088 $ 21,866 $ 27,115 Intersegment revenues — — — — 11,540 14,088 21,866 27,115 Investment in Lake Charles LNG: Revenues from external customers 54 53 108 107 Adjustments and Eliminations — 2 — 1 Total revenues $ 11,594 $ 14,143 $ 21,974 $ 27,223
Investment In ETP [Member]
Revenue from External Customers by Products and Services [Table Text Block]	Investment in ETP Three Months Ended Six Months Ended 2015 2014 2015 2014 Intrastate Transportation and Storage $ 486 $ 667 $ 1,027 $ 1,512 Interstate Transportation and Storage 239 245 510 540 Midstream 771 1,297 1,524 2,349 Liquids Transportation and Services 779 867 1,587 1,659 Investment in Sunoco Logistics 3,121 4,766 5,647 9,218 Retail Marketing 5,557 5,568 10,339 10,576 All Other 587 678 1,232 1,261 Total revenues 11,540 14,088 21,866 27,115 Less: Intersegment revenues — — — — Revenues from external customers $ 11,540 $ 14,088 $ 21,866 $ 27,115

Supplemental Financial Statem33

Supplemental Financial Statement Information (Tables)	6 Months Ended
	Jun. 30, 2015
Parent [Member]
Schedule Of Balance Sheets	BALANCE SHEETS (unaudited) June 30, December 31, 2014 ASSETS Current assets: Cash and cash equivalents $ 1 $ 2 Accounts receivable from related companies 21 14 Other current assets 1 1 Total current assets 23 17 Property, plant and equipment, net 7 — Advances to and investments in unconsolidated affiliates 6,406 5,390 Intangible assets, net 8 10 Goodwill 9 9 Other non-current assets, net 52 46 Total assets $ 6,505 $ 5,472 LIABILITIES AND PARTNERS’ CAPITAL Current liabilities: Accounts payable to related companies $ 84 $ 11 Interest payable 71 58 Accrued and other current liabilities 2 3 Total current liabilities 157 72 Long-term debt, less current maturities 5,737 4,680 Note payable to affiliate 109 54 Other non-current liabilities 1 2 Commitments and contingencies Partners’ capital: General Partner (1 ) (1 ) Limited Partners: Common Unitholders 484 648 Class D Units 20 22 Accumulated other comprehensive loss (2 ) (5 ) Total partners’ capital 501 664 Total liabilities and partners’ capital $ 6,505 $ 5,472
Schedule Of Statements Of Operations	STATEMENTS OF OPERATIONS (unaudited) Three Months Ended Six Months Ended 2015 2014 2015 2014 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES (1) $ (29 ) $ (32 ) $ (57 ) $ (63 ) OTHER INCOME (EXPENSE): Interest expense, net of interest capitalized (72 ) (50 ) (133 ) (90 ) Equity in earnings of unconsolidated affiliates 398 248 771 487 Other, net — (2 ) 1 (2 ) INCOME BEFORE INCOME TAXES 297 164 582 332 Income tax benefit (1 ) — — — NET INCOME 298 164 582 332 General Partner’s interest in net income — 1 1 1 Class D Unitholder’s interest in net income — — 1 1 Limited Partners’ interest in net income $ 298 $ 163 $ 580 $ 330 (1) Includes management fees paid by ETE to ETP.
Parent Company [Member]
Schedule Of Statements Of Cash Flows	STATEMENTS OF CASH FLOWS (unaudited) Six Months Ended 2015 2014 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 475 $ 497 CASH FLOWS FROM INVESTING ACTIVITIES: Cash paid for Bakken Pipeline Transaction (817 ) — Contributions to unconsolidated affiliate — (8 ) Capital expenditures (7 ) — Purchase of additional interest in Regency — (400 ) Cash received from affiliate 106 — Net cash used in investing activities (718 ) (408 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings 2,972 2,390 Principal payments on debt (1,915 ) (1,051 ) Distributions to partners (509 ) (391 ) Units repurchased under buyback program (294 ) (1,000 ) Debt issuance costs (12 ) (14 ) Net cash provided by (used in) financing activities 242 (66 ) INCREASE IN CASH AND CASH EQUIVALENTS (1 ) 23 CASH AND CASH EQUIVALENTS, beginning of period 2 8 CASH AND CASH EQUIVALENTS, end of period $ 1 $ 31

Operations And Organization Nar

Operations And Organization Narrative (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)Bcf	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)Bcf	Jun. 30, 2014USD ($)
Lone Star L.L.C. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
Citrus [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
Trunkline LNG [Member]
LNG Storage Capacity | Bcf	9		9
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%
Retail Marketing [Member]
Excise Taxes Collected	$ 762	$ 573	$ 1,500	$ 1,100
Regency Merger [Member] | Regency [Member] | Lone Star L.L.C. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			30.00%

Acquisitions Narrative (Details

Acquisitions Narrative (Details) $ in Millions, gallons in Billions	1 Months Ended		6 Months Ended	12 Months Ended
	Apr. 30, 2015USD ($)shares	Mar. 31, 2015USD ($)	Jun. 30, 2015USD ($)gallonsshares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Proposed WMB Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share			1.8716
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 | gallons			5.3
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%
Interest ownership			45.00%
Class I Distributions | $				$ 30	$ 55
Dropdown of Susser [Member]
Business Combination, Consideration Transferred | $	$ 967		$ 1,930
Payments to Acquire Businesses, Gross | $			967
Sunoco LP Exchange [Member]
IDR Subsidies | $			$ 35
Term of IDR Subsidy
Stock Repurchased During Period, Shares			21,000,000
Susser [Member] | Dropdown of Susser [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Sunoco LP [Member] | Dropdown of Susser [Member]
Sale of Stock, Number of Shares Issued in Transaction			22,000,000
Sunoco GP [Member] | Sunoco LP Exchange [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			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
Class H Units [Member] | Bakken Pipeline Transaction [Member]
Business Acquisition Units Acquired			30,800,000
Class I Units [Member] | Bakken Pipeline Transaction [Member]
Business Acquisition Units Acquired			100
First year post closing [Member] | Regency Merger [Member]
IDR Subsidies | $	$ 80
Four years post closing [Member] | Regency Merger [Member]
IDR Subsidies | $	$ 60
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%
ETP [Member] | Sunoco LP [Member] | Dropdown of Susser [Member]
Sale of Stock, Number of Shares Issued in Transaction			11,000,000
Susser [Member] | Sunoco LP [Member] | Dropdown of Susser [Member]
Sale of Stock, Number of Shares Issued in Transaction			11,000,000

Cash And Cash Equivalents Table

Cash And Cash Equivalents Table - Schedule of Non-Cash Investing & Financing Activities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 693	$ 339
Accrued advances to unconsolidated affiliates	0	175
Net gains from subsidiary common unit issuances	50	560
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with PVR and Hoover acquisitions	0	4,015
Long-term debt assumed in PVR acquisition	$ 0	$ 1,887

Inventories Table - Inventory B

Inventories Table - Inventory Balances (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Inventory, Net [Abstract]
Natural gas and NGLs	$ 425	$ 392
Crude oil	599	364
Refined products	446	392
Other	388	319
Total inventories	$ 1,858	$ 1,467

Fair Value Measurements Narrati

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 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	35,180	$ 31,680
Long-term Debt	$ 34,810	$ 30,661

Fair Value Measurements Table -

Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Liabilities, Fair Value Disclosure, Recurring	$ (365)	$ (749)
Fair Value, Inputs, Level 1 [Member]
Liabilities, Fair Value Disclosure, Recurring	(243)	(551)
Fair Value, Inputs, Level 2 [Member]
Liabilities, Fair Value Disclosure, Recurring	(110)	(182)
Level 3 [Member]
Liabilities, Fair Value Disclosure, Recurring	(12)	(16)
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	2
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	2
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]
Interest Rate Derivative Assets, at Fair Value	1	3
Price Risk Derivative Assets, at Fair Value	273	745
Assets, Fair Value Disclosure	274	748
Interest Rate Derivative Liabilities, at Fair Value	(105)	(155)
Embedded Derivative, Fair Value of Embedded Derivative Liability	(12)	(16)
Price Risk Derivative Liabilities, at Fair Value	(248)	(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	265	632
Assets, Fair Value Disclosure	265	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	(243)	(551)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Interest Rate Derivative Assets, at Fair Value	1	3
Price Risk Derivative Assets, at Fair Value	8	113
Assets, Fair Value Disclosure	9	116
Interest Rate Derivative Liabilities, at Fair Value	(105)	(155)
Embedded Derivative, Fair Value of Embedded Derivative Liability	0	0
Price Risk Derivative Liabilities, at Fair Value	(5)	(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	(12)	(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		36
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
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		36
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 3 [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, 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	7	19
Price Risk Derivative Liabilities, at Fair Value	(7)	(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	(2)	(25)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	213	566
Price Risk Derivative Liabilities, at Fair Value	(189)	(490)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, 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	7	19
Price Risk Derivative Liabilities, at Fair Value	(7)	(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	213	541
Price Risk Derivative Liabilities, at Fair Value	(189)	(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
Price Risk Derivative Liabilities, 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	(1)	(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	0	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
Price Risk Derivative Liabilities, 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
Price Risk Derivative Liabilities, at Fair Value	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	6	21
Price Risk Derivative Liabilities, at Fair Value	(6)	(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	6	21
Price Risk Derivative Liabilities, at Fair Value	(6)	(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	4	3
Price Risk Derivative Liabilities, at Fair Value	(3)	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	3
Price Risk Derivative Liabilities, at Fair Value	(7)
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	5
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	3
Price Risk Derivative Liabilities, at Fair Value	(7)
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	5
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	4	3
Price Risk Derivative Liabilities, at Fair Value	(3)	(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	31	69
Price Risk Derivative Liabilities, at Fair Value	(29)	(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	31	46
Price Risk Derivative Liabilities, at Fair Value	(29)	(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	0	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 Table40

Fair Value Measurements Table - Reconciliation of Level 3 Derivatives (Details) $ in Millions	6 Months Ended
	Jun. 30, 2015USD ($)
Net unrealized gains included in other income (expense)	$ 4
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Balance, December 31, 2014	(16)
Balance, June 30, 2015	$ (12)

Net Income per Limited Partne41

Net Income per Limited Partner Unit Table - Income Reconciliation (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]
Income from continuing operations	$ 772	$ 458	$ 993	$ 882
Less: Income from continuing operations attributable to noncontrolling interest	474	298	411	557
Income from continuing operations, net of noncontrolling interest	298	160	582	325
Less: General Partner’s interest in income from continuing operations	0	1	1	1
Less: Class D Unitholder’s interest in income from continuing operations	0	0	1	1
Income from continuing operations available to Limited Partners	298	159	580	323
Dilutive Effect of Equity Based Compensation of Subsidiaries	$ (1)	$ 0	$ (1)	$ 1
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average Limited Partner units	1,076	1,087.3	1,077.2	1,101.2
Basic income from continuing operations per Limited Partner unit	$ 0.28	$ 0.15	$ 0.54	$ 0.29
Basic income from discontinued operations per Limited Partner unit	$ 0	$ 0	$ 0	$ 0.01
Diluted Income from Continuing Operations per Limited Partner Unit:
Dilutive Effect of Equity Based Compensation of Subsidiaries	$ (1)	$ 0	$ (1)	$ 1
Diluted income from continuing operations available to Limited Partners	$ 299	$ 159	$ 581	$ 322
Dilutive effect of unconverted unit awards	1.6	1.8	1.8	1.8
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	1,077.6	1,089.1	1,079	1,103
Diluted income from continuing operations per Limited Partner unit	$ 0.28	$ 0.15	$ 0.54	$ 0.29
Diluted income from discontinued operations per Limited Partner unit	$ 0	$ 0	$ 0	$ 0.01

Debt Obligations Narrative (Det

Debt Obligations Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2015	Jun. 30, 2014	Jul. 31, 2015	Apr. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt			$ 15,466	$ 8,023
Parent Company [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt			2,972	$ 2,390
ETP [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt	$ 2,980	$ 2,480
4.5% Senior Notes due November 1, 2023 [Member] | Regency [Member]
Debt Instrument [Line Items]
Senior Notes	$ 600		$ 600
Debt Instrument, Interest Rate, Stated Percentage	4.50%		4.50%
4.15% Senior Notes due October 1, 2020 [Member] | ETP [Member]
Debt Instrument [Line Items]
Senior Notes	$ 350		$ 350
Debt Instrument, Interest Rate, Stated Percentage	4.15%		4.15%
8.375% Senior Notes due June 1, 2019 [Member] | Regency [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.375%		8.375%
Early Repayment of Senior Debt			$ 499
8.375% Senior Notes due June 1, 2020 [Member] | Regency [Member]
Debt Instrument [Line Items]
Senior Notes	$ 390		390
6.5% Senior Notes due May 15, 2021 [Member] | Regency [Member]
Debt Instrument [Line Items]
Senior Notes	$ 400		$ 400
Debt Instrument, Interest Rate, Stated Percentage	6.50%		6.50%
4.05% Senior Notes due March 2025 [Member] | ETP [Member]
Debt Instrument [Line Items]
Senior Notes	$ 1,000		$ 1,000
Debt Instrument, Interest Rate, Stated Percentage	4.05%		4.05%
4.90% Senior Notes due March 2035 [Member] | ETP [Member]
Debt Instrument [Line Items]
Senior Notes	$ 500		$ 500
Debt Instrument, Interest Rate, Stated Percentage	4.90%		4.90%
5.15% Senior Notes due March 2045 [Member] | ETP [Member]
Debt Instrument [Line Items]
Senior Notes	$ 1,000		$ 1,000
Debt Instrument, Interest Rate, Stated Percentage	5.15%		5.15%
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member]
Debt Instrument [Line Items]
Senior Notes						$ 800
Debt Instrument, Interest Rate, Stated Percentage						6.375%
5.5% Senior Notes due August 2020 [Member] | Sunoco LP [Member]
Debt Instrument [Line Items]
Senior Notes					$ 600
Debt Instrument, Interest Rate, Stated Percentage					5.50%
5.875% Senior Notes due January 15, 2024 [Member] | Parent Company [Member]
Debt Instrument [Line Items]
Senior Notes	$ 1,150		$ 1,150
Debt Instrument, Interest Rate, Stated Percentage	5.875%		5.875%
2.50% Senior Notes due June 2018 [Member] | ETP [Member]
Debt Instrument [Line Items]
Senior Notes	$ 650		$ 650
Debt Instrument, Interest Rate, Stated Percentage	2.50%		2.50%
ETE Senior Secured Revolving Credit Facilities [Member] | Parent Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 1,500		$ 1,500
Line of Credit Facility, Amount Outstanding	230		230
Line of Credit Facility, Remaining Borrowing Capacity	1,270		1,270
5.5% Senior Notes due June 1, 2027 [Member] | Parent Company [Member]
Debt Instrument [Line Items]
Senior Notes	$ 1,000		$ 1,000
Debt Instrument, Interest Rate, Stated Percentage	5.50%		5.50%
ETE 7.5% Senior Notes due 2020 [Member] | Parent Company [Member]
Debt Instrument [Line Items]
Senior Notes	$ 1,190		$ 1,190
Debt Instrument, Interest Rate, Stated Percentage	7.50%		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		$ 3,750
Line of Credit Facility, Amount Outstanding	0		0
Regency Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	2,500		2,500
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		2,500				$ 1,500
Line of Credit Facility, Amount Outstanding	550		550
Line of Credit Facility, Maximum Borrowing Capacity	3,250		3,250
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		1,500
Line Of Credit Facility, Additional Borrowing Capacity Subject To Lender Approval	250		250
Line of Credit Facility, Amount Outstanding	725		725
4.75% Senior Notes due January 2026 [Member] | ETP [Member]
Debt Instrument [Line Items]
Senior Notes	$ 1,000		$ 1,000
Debt Instrument, Interest Rate, Stated Percentage	4.75%		4.75%
6.125% Senior Notes due December 2045 [Member] | ETP [Member]
Debt Instrument [Line Items]
Senior Notes	$ 1,000		$ 1,000
Debt Instrument, Interest Rate, Stated Percentage	6.125%		6.125%
Senior Secured Term Loan B Agreement [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 1,400		$ 1,400
Senior Secured Term Loan B Agreement [Member] | 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			2.50%
Senior Secured Term Loan B Agreement [Member] | 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			1.50%
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		$ 850
Senior Secured Term Loan C Agreement [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 2,250		$ 2,250
Senior Secured Term Loan C Agreement [Member] | 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%
Senior Secured Term Loan C Agreement [Member] | 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%

Equity Narrative (Details)

Equity Narrative (Details) - USD ($) $ in Millions	1 Months Ended		6 Months Ended		12 Months Ended
	Apr. 30, 2015	Mar. 31, 2015	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Units repurchased under buyback program			$ 294	$ 1,000
Stock Repurchase Program, Authorized Amount			2,000
Net gains from subsidiary common unit issuances			$ 50	$ 560
Stock Issued During Period, Shares, New Issues			900,000
ETP [Member]
Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount			$ 832
Stock Issued During Period, Value, Dividend Reinvestment Plan			$ 155
Stock Issued During Period, Shares, Dividend Reinvestment Plan			2,800,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan			4,500,000
Sunoco Logistics [Member]
Proceeds from Issuance of Common Stock, net	$ 82		$ 547
Partners' Capital Account, Units, Sale of Units			13,500,000
Stock Issued During Period, Shares, New Issues	2,000,000
Sunoco LP [Member]
Proceeds from Issuance of Common Stock, net			$ 213
Stock Issued During Period, Shares, New Issues	5,500,000
Equity distribution agreement [Member] | ETP [Member]
Proceeds from Issuance of Common Stock, net			569
Fees and Commissions			6
Equity distribution agreement [Member] | Regency [Member]
Proceeds from Issuance of Common Limited Partners Units			34
Equity distribution agreement [Member] | Sunoco Logistics [Member]
Proceeds from Issuance of Common Limited Partners Units			385
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units			1,250
Fees and Commissions			$ 4
Class H Units [Member]
Business Acquisition Units Acquired			50,200,000
Sunoco Logistics Revolving Credit Facility, due March 2020 [Member] | Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity			$ 2,500				$ 1,500
Bakken Pipeline Transaction [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			30,800,000
Interest ownership			45.00%
Payments to Acquire Businesses, Gross		$ 879
Class H Interest in Sunoco Logistics			90.05%
Class I Distributions					$ 30	$ 55
Bakken Pipeline Transaction [Member] | Class H Units [Member]
Business Acquisition Units Acquired			30,800,000
Bakken Pipeline Transaction [Member] | Class I Units [Member]
Business Acquisition Units Acquired			100

Equity Table - Change In ETE Co

Equity Table - Change In ETE Common Units (Details) shares in Millions	6 Months Ended
	Jun. 30, 2015shares
Partners' Capital Notes [Abstract]
Outstanding at December 31, 2014	1,077.5
Stock Issued During Period, Shares, New Issues	0.9
Stock Repurchased and Retired During Period, Shares	(8.6)
Outstanding at June 30, 2015	1,069.8

Equity Table - Quarterly Distri

Equity Table - Quarterly Distributions of Available Cash (Details) - $ / shares	3 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Regency [Member]
Distribution Made to Limited Partner, Date of Record			Feb. 6, 2015
Distribution Made to Limited Partner, Distribution Date			Feb. 13, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit			$ 0.5025
Sunoco Logistics [Member]
Distribution Made to Limited Partner, Date of Record	Aug. 10, 2015	May 11, 2015	Feb. 9, 2015
Distribution Made to Limited Partner, Distribution Date	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.4380	$ 0.4190	$ 0.4000
Parent Company [Member]
Distribution Made to Limited Partner, Date of Record	Aug. 6, 2015	May 8, 2015	Feb. 6, 2015
Distribution Made to Limited Partner, Distribution Date	Aug. 19, 2015	May 19, 2015	Feb. 19, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.265	$ 0.2450	$ 0.2250
ETP [Member]
Distribution Made to Limited Partner, Date of Record	Aug. 6, 2015	May 8, 2015	Feb. 6, 2015
Distribution Made to Limited Partner, Distribution Date	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 1.035	$ 1.0150	$ 0.9950
Sunoco LP [Member]
Distribution Made to Limited Partner, Date of Record	Aug. 18, 2015	May 19, 2015	Feb. 17, 2015
Distribution Made to Limited Partner, Distribution Date	Aug. 28, 2015	May 29, 2015	Feb. 27, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.6934	$ 0.6450	$ 0.6000

Equity Table - IDR Schedule (De

Equity Table - IDR Schedule (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Equity [Abstract]
Relinquishment of Rights of Incentive Distributions	$ 56	$ 95	$ 105	$ 128	$ 137

Equity Table - Accumulated Othe

Equity Table - Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 3	$ 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	(14)	(56)
Amounts attributable to noncontrolling interest	12	51
Accumulated other comprehensive income, net	$ (2)	$ (5)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jul. 31, 2015
Increase in dividends received deduction [Member]
Deferred Income Tax Expense (Benefit)	$ 22
Reduction in franchise tax [Member]
Deferred Income Tax Expense (Benefit)	11
Unfavorable [Member]
Tax Adjustments, Settlements, and Unusual Provisions		$ 87
Tax Year 2006 [Member]
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority			$ (6)
Amount of Deferred Gain Challenged by IRS			545
Deferred Gain Associated with Like Kind Exchange			$ 690
Sunoco [Member]
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	87
Sunoco [Member] | Net of federal tax [Member]
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	$ 57

Regulatory Matters, Commitmen49

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)		1 Months Ended			3 Months Ended		6 Months Ended
		Sep. 30, 2013USD ($)	Nov. 30, 2012USD ($)	Jan. 31, 2012USD ($)	Jun. 30, 2015USD ($)sites	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)sites	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Apr. 30, 2013USD ($)
Lease Expiration Date							Dec. 31, 2058
Operating Leases, Rent Expense	[1]				$ 54,000,000	$ 27,000,000	$ 106,000,000	$ 59,000,000
Operating Leases, Rent Expense, Contingent Rentals					6,000,000	6,000,000	10,000,000	9,000,000
Loss Contingency Accrual, at Carrying Value					38,000,000		38,000,000		$ 37,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed					$ 0		$ 0
Site Contingency, Number of Sites Needing Remediation | sites					19		19
Environmental Costs Recognized, Recovery Credited to Expense							$ 19,000,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount					$ 319,000,000		319,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount					595,000,000		595,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount					1,000,000		1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount					$ 536,000,000		$ 536,000,000
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
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number					6		6
Sunoco, Inc. [Member] | Multidistrict Legislation [Member]
Loss Contingency, Pending Claims, Number					4		4
Southern Union [Member]
Percentage Of Recovery							50.00%
Loss Contingency, Estimated Recovery from Third Party							150,000
Sunoco [Member]
Payments for Environmental Liabilities					$ 11,000,000	$ 9,000,000	$ 18,000,000	$ 17,000,000
Site Contingency, Number of Sites Needing Remediation					52		52
[1]	(1) Includes contingent rentals totaling

Regulatory Matters, Commitmen50

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Environmental Exit Cost [Line Items]
Current	$ 49	$ 41
Non-current	334	360
Total environmental liabilities	$ 383	$ 401

Regulatory Matters, Commitmen51

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Rent expense table (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating Leases, Rent Expense	[1]	$ 54	$ 27	$ 106	$ 59
Operating Leases, Rent Expense, Sublease Rentals		4	10	12	18
Operating Leases, Rent Expense, Net		$ 50	$ 17	$ 94	$ 41
[1]	(1) Includes contingent rentals totaling

Derivative Assets And Liabili52

Derivative Assets And Liabilities Narrative (Details) $ in Millions	3 Months Ended
	Jun. 30, 2015USD ($)
Regency [Member]
Proceeds From Termination of Commodity Swaps	$ 56

Derivative Assets And Liabili53

Derivative Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details)		6 Months Ended	12 Months Ended
		Jun. 30, 2015barrelsbblMegawattMMbtu	Dec. 31, 2014barrelsbblMegawattMMbtu
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Notional Volume		10,327,500	57,500
Maximum Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member]
Notional Volume		23,335,000	46,150,000
Maximum Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Notional Volume		(11,577,500)	(34,304,000)
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Options - Puts [Member] | Power [Member]
Notional Volume | Megawatt		(581,328)	(72,000)
Maximum Term Of Commodity Derivatives		2,015	2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Call Option [Member] | Power [Member]
Notional Volume | Megawatt		(1,428,154)	198,556
Maximum Term Of Commodity Derivatives		2,015	2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Natural Gas [Member]
Notional Volume		4,424,847	(9,116,777)
Maximum Term Of Commodity Derivatives		2,015	2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Natural Gas Liquids and Crude [Member]
Notional Volume | bbl		(3,730,800)	(4,417,400)
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Power [Member]
Notional Volume | Megawatt		373,357	288,775
Maximum Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Refined Products [Member]
Notional Volume | barrels		(1,195,000)	13,745,755
Maximum Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Power [Member]
Notional Volume | Megawatt		436,789	(156,000)
Maximum Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Notional Volume	[1]	(4,527,500)	(13,907,500)
Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Notional Volume		(1,075,000)	(232,500)
Maximum Term Of Commodity Derivatives			2,015
Mark-To-Market Derivatives [Member] | Trading [Member] | Call Option [Member] | Natural Gas [Member]
Notional Volume		5,000,000	5,000,000
Maximum Term Of Commodity Derivatives		2,015	2,015
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,016	2,016
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Forwards Swaps [Member] | Natural Gas Liquids and Crude [Member]
Maximum Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Forwards Swaps [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Future [Member] | Refined Products [Member]
Maximum Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Future [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,016	2,016
Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,015
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,015
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,015	2,015
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Forwards Swaps [Member] | Natural Gas Liquids and Crude [Member]
Maximum Term Of Commodity Derivatives		2,015
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Forwards Swaps [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2,015
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Future [Member] | Refined Products [Member]
Maximum Term Of Commodity Derivatives		2,015
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Future [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2,015
Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,015	2,015
Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2,015
Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Notional Volume		(37,555,000)	(39,287,500)
Maximum Term Of Commodity Derivatives		2,016	2,015
Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Notional Volume		(37,555,000)	(39,287,500)
Maximum Term Of Commodity Derivatives		2,016	2,015
Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Natural Gas [Member]
Notional Volume		37,555,000	39,287,500
Maximum Term Of Commodity Derivatives		2,016	2,015
[1]	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Derivative Assets And Liabili54

Derivative Assets And Liabilities Table - Interest Rate Swaps Outstanding (Details) - Interest Rate Derivatives [Member] - ETP [Member] - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2015	Dec. 31, 2014
March 2019 [Member]
Notional Amount		$ 300	$ 0
Type	[1]	Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.42%
December 2018 [Member]
Notional Amount		$ 1,200	0
Type	[1]	Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53%
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	[2]	$ 100	200
Type	[2]	Forward-starting to pay a fixed rate of 3.40% and receive a floating rate
Forward-Starting Swaps [Member] | July 2016 [Member]
Notional Amount	[3]	$ 200	200
Type	[3]	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
Forward-Starting Swaps [Member] | July 2017 [Member]
Notional Amount	[4]	$ 300	300
Type	[4]	Forward-starting to pay a fixed rate of 3.84% and receive a floating rate
Forward-Starting Swaps [Member] | July 2018 [Member]
Notional Amount	[4]	$ 200	200
Type	[4]	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
Forward-Starting Swaps [Member] | July 2019 [Member]
Notional Amount	[4]	$ 200	$ 300
Type	[4]	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate
[1]	(1) Floating rates are based on 3-month LIBOR.
[2]	(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]	(3) Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
[4]	(4) Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

Derivative Assets And Liabili55

Derivative Assets And Liabilities Table - Fair Value of Derivative Instruments (Details) - Hedging Relationship [Domain] - Derivative Contract Type [Domain] - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Total derivatives assets	$ 287	$ 770
Total derivatives liabilities	378	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	284	727
Total derivatives liabilities	378	771
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	265	617
Total derivatives liabilities	245	577
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	18	107
Total derivatives liabilities	16	23
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivatives assets	1	3
Total derivatives liabilities	105	155
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ 12	$ 16

Derivative Assets And Liabili56

Derivative Assets And Liabilities Table - Gross FV and Netting Offset (Details) - Hedging Designation [Domain] - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 287	$ 770
Derivative Liability, Fair Value, Gross Liability	(378)	(771)
Derivative Asset, Fair Value, Amount Offset Against Collateral	4	(14)
Derivative Liability, Fair Value, Amount Offset Against Collateral	3	(3)
Netting [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	282	697
Derivative Liability, Fair Value, Gross Liability	(264)	(597)
Derivative Asset, Fair Value, Gross Liability	(12)	(19)
Derivative Liability, Fair Value, Gross Asset	12	19
Derivative Asset, Fair Value, Net	286	683
Derivative Liability, Fair Value, Net	(261)	(600)
Netting [Member] | OTC contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	18	23
Derivative Liability, Fair Value, Gross Liability	(16)	(23)
Netting [Member] | Broker cleared derivative contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	264	674
Derivative Liability, Fair Value, Gross Liability	(248)	(574)
Netting [Member] | Asset Fair Value, Netting Offset [Member]
Derivatives, Fair Value [Line Items]
Payments on Margin Deposits	16	5
Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value	1	87
Netting [Member] | Liability Fair Value, Netting Offset [Member]
Derivatives, Fair Value [Line Items]
Payments on Margin Deposits	(9)	(22)
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value	$ (117)	$ (171)

Derivative Assets And Liabili57

Derivative Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Recognized OCI on Derivatives (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ (2)	$ 1	$ (6)
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ (2)	$ 1	$ (6)

Derivative Assets And Liabili58

Derivative Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Amount of Gain (Loss) Recognized (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$ 0	$ (2)	$ 0	$ (6)
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	11	0	8	(6)
Amount of Gain/(Loss) Recognized in Income on Derivatives	83	(97)	(2)	(99)
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(6)	(5)	(8)	2
Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	0	(2)	0	(6)
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	11	0	8	(6)
Amount of Gain/(Loss) Recognized in Income on Derivatives	(40)	(37)	(48)	(43)
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	127	(46)	50	(48)
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 2	$ (9)	$ 4	$ (10)

Related Party Transactions Rela

Related Party Transactions Related Party Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Related Party Transactions [Abstract]
Revenue from Related Parties	$ 130	$ 362	$ 206	$ 690

Other Information Table - Other

Other Information Table - Other Current Assets (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Other Information [Abstract]
Deposits paid to vendors	$ 36	$ 65
Deferred income taxes	0	14
Income taxes receivable	151	17
Prepaid expenses and other	195	205
Total other current assets	$ 382	$ 301

Other Information Table - Accru

Other Information Table - Accrued and Other Current Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Other Information [Abstract]
Interest payable	$ 468	$ 440
Customer advances and deposits	100	103
Accrued capital expenditures	608	673
Accrued wages and benefits	156	233
Taxes payable other than income taxes	302	236
Income taxes payable	4	54
Deferred income taxes	99	99
Other	321	363
Total accrued and other current liabilities	$ 2,058	$ 2,201

Reportable Segments Narrative (

Reportable Segments Narrative (Details) - Entities [Domain] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Revenues	$ 11,594	$ 14,143	$ 21,974	$ 27,223
Lone Star L.L.C. [Member]
Segment Reporting Information [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
External Customers [Member] | Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Revenues	$ 54	$ 53	$ 108	$ 107

Reportable Segments Table - Seg

Reportable Segments Table - Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 1,512	$ 1,440	$ 2,904	$ 2,815
Depreciation, depletion and amortization	(514)	(450)	(1,007)	(823)
Interest Expense, net of interest capitalized	(408)	(344)	(779)	(659)
Gain on sale of AmeriGas common units	0	93	0	163
Gains (losses) on interest rate derivatives	127	(46)	50	(48)
Non-cash unit-based compensation expense	(25)	(20)	(48)	(40)
Unrealized Gain (Loss) on commodity risk management activities	(44)	(10)	(119)	(43)
LIFO valuation adjustment	184	20	150	34
Equity in earnings of unconsolidated affiliates	117	77	174	181
Adjusted EBITDA related to unconsolidated affiliates	(215)	(190)	(361)	(400)
Adjusted EBITDA related to discontinued operations	0	0	0	(27)
Other, net	(18)	(42)	(15)	(56)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	716	528	949	1,097
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	1,488	1,393	2,854	2,731
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	49	47	98	95
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	(25)	(29)	(48)	(55)
Adjustments And Eliminations [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 0	$ 29	$ 0	$ 44

Reportable Segments Table - S64

Reportable Segments Table - Segment Assets (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Assets	$ 69,145	$ 64,469
Investment In ETP [Member]
Assets	67,551	62,674
Investment in Lake Charles LNG [Member]
Assets	1,289	1,210
Corporate and Other [Member]
Assets	666	1,153
Adjustments And Eliminations [Member]
Assets	$ (361)	$ (568)

Reportable Segments Table - Rev

Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues	$ 11,594	$ 14,143	$ 21,974	$ 27,223
Investment In ETP [Member]
Revenues	11,540	14,088	21,866	27,115
Adjustments And Eliminations [Member]
Revenues	0	2	0	1
Intersegment [Member] | Investment In ETP [Member]
Revenues	0	0	0	0
External Customers [Member] | Investment In ETP [Member]
Revenues	11,540	14,088	21,866	27,115
External Customers [Member] | Investment in Lake Charles LNG [Member]
Revenues	$ 54	$ 53	$ 108	$ 107

Reportable Segments Table - R66

Reportable Segments Table - Revenues from External Customers by Segment (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Revenues	$ 11,594	$ 14,143	$ 21,974	$ 27,223
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	11,540	14,088	21,866	27,115
Intrastate Transportation And Storage [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	486	667	1,027	1,512
Interstate Transportation and Storage [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	239	245	510	540
Midstream [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	771	1,297	1,524	2,349
Liquids Transportation And Services [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	779	867	1,587	1,659
Investment in Sunoco Logistics [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	3,121	4,766	5,647	9,218
Retail Marketing [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	5,557	5,568	10,339	10,576
Other Segments [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	587	678	1,232	1,261
Intersegment [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
External Customers [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	$ 11,540	$ 14,088	$ 21,866	$ 27,115

Supplemental Financial Statem67

Supplemental Financial Statement Information Table - Balance Sheets (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Cash and cash equivalents	$ 1,623	$ 847	$ 1,234	$ 590
Accounts receivable from related companies	124	35
Other current assets	382	301
Total current assets	7,237	6,153
Property, Plant and Equipment, Net	44,047	40,292
Advances to and investments in unconsolidated affiliates	3,653	3,659
Intangible assets, net	5,579	5,582
Goodwill	7,663	7,865
Other non-current assets, net	965	908
Total Assets	69,145	64,469
Accounts payable	3,009	3,349
Accounts payable to related companies	7	19
Interest payable	468	440
Derivative liabilities	12	21
Accrued and other current liabilities	2,058	2,201
Current maturities of long-term debt	15	1,008
Total current liabilities	5,238	6,782
Long-term debt, less current maturities	34,795	29,653
Preferred units of subsidiaries	33	33
Other non-current liabilities	$ 1,226	$ 1,193
COMMITMENTS AND CONTINGENCIES
General Partner	$ (1)	$ (1)
Common Unitholders	484	648
Class D Units	20	22
Accumulated other comprehensive loss	(2)	(5)
Total partners’ capital	501	664
Total Liabilities and Equity	69,145	64,469
Parent Company [Member]
Cash and cash equivalents	1	2	$ 31	$ 8
Accounts receivable from related companies	21	14
Other current assets	1	1
Total current assets	23	17
Property, Plant and Equipment, Net	7	0
Advances to and investments in unconsolidated affiliates	6,406	5,390
Intangible assets, net	8	10
Goodwill	9	9
Other non-current assets, net	52	46
Total Assets	6,505	5,472
Accounts payable to related companies	84	11
Interest payable	71	58
Accrued and other current liabilities	2	3
Total current liabilities	157	72
Long-term debt, less current maturities	5,737	4,680
Notes Payable, Related Parties, Noncurrent	109	54
Other non-current liabilities	$ 1	$ 2
COMMITMENTS AND CONTINGENCIES
General Partner	$ (1)	$ (1)
Common Unitholders	484	648
Class D Units	20	22
Accumulated other comprehensive loss	(2)	(5)
Total partners’ capital	501	664
Total Liabilities and Equity	$ 6,505	$ 5,472

Supplemental Financial Statem68

Supplemental Financial Statement Information Schedule of Statements of Operations (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES		$ (183)	$ (141)	$ (338)	$ (272)
Interest Expense, net of interest capitalized		(408)	(344)	(779)	(659)
Equity in earnings of unconsolidated affiliates		117	77	174	181
Gains on interest rate derivatives		127	(46)	50	(48)
Other, net		(16)	(25)	(9)	(23)
Income tax expense (benefit)		(56)	70	(44)	215
NET INCOME ATTRIBUTABLE TO PARTNERS		298	164	582	332
General Partner’s interest in net income		0	1	1	1
Class D Unitholder’s interest in net income		0	0	1	1
Limited Partners’ interest in net income		298	163	580	330
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	[1]	(29)	(32)	(57)	(63)
Interest Expense, net of interest capitalized		(72)	(50)	(133)	(90)
Equity in earnings of unconsolidated affiliates		398	248	771	487
Other, net		0	(2)	1	(2)
INCOME BEFORE INCOME TAXES		297	164	582	332
Income tax expense (benefit)		(1)	0	0	0
NET INCOME ATTRIBUTABLE TO PARTNERS		298	164	582	332
General Partner’s interest in net income		0	1	1	1
Class D Unitholder’s interest in net income		0	0	1	1
Limited Partners’ interest in net income		$ 298	$ 163	$ 580	$ 330
[1]	(1) Includes management fees paid by ETE to ETP.

Supplemental Financial Statem69

Supplemental Financial Statement Information Schedule Of Statements of Cash Flows (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$ 1,113	$ 1,895
Cash paid for Bakken Pipeline Transaction	(475)	(407)
Capital expenditures	4,181	2,137
Net cash used in investing activities	(4,673)	(1,668)
Proceeds from borrowings	15,466	8,023
Repayments of long-term debt	(11,301)	(5,964)
Distributions to partners	509	391
Units repurchased under buyback program	294	1,000
Debt issuance costs	(61)	(44)
Net cash provided by (used in) financing activities	4,336	417
INCREASE IN CASH AND CASH EQUIVALENTS	776	644
Cash and cash equivalents, beginning of period	847	590
Cash and cash equivalents, end of period	1,623	1,234
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	475	497
Cash paid for Bakken Pipeline Transaction	(817)	0
Contributions to unconsolidated affiliates	0	8
Capital expenditures	(7)	0
Purchase of additional interest in Regency	0	400
Cash received from affiliate	106	0
Net cash used in investing activities	(718)	(408)
Proceeds from borrowings	2,972	2,390
Repayments of long-term debt	(1,915)	(1,051)
Distributions to partners	(509)	(391)
Units repurchased under buyback program	(294)	(1,000)
Debt issuance costs	(12)	(14)
Net cash provided by (used in) financing activities	242	(66)
INCREASE IN CASH AND CASH EQUIVALENTS	(1)	23
Cash and cash equivalents, beginning of period	2	8
Cash and cash equivalents, end of period	$ 1	$ 31