Energy Transfer 10-Q 7 Nov 13 2013 Q3 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 01, 2013
Document Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Entity Information [Abstract]	'	'
Entity Registrant Name	'Energy Transfer Partners, L.P.	'
Entity Central Index Key	'0001012569	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	330,159,209

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents	$1,064	$311
Accounts receivable, net	3,288	2,910
Accounts receivable from related companies	177	94
Inventories	1,657	1,495
Exchanges receivable	32	55
Price risk management assets	30	21
Current assets held for sale	16	184
Other current assets	318	334
Total current assets	6,582	5,404
PROPERTY, PLANT AND EQUIPMENT	27,352	27,412
ACCUMULATED DEPRECIATION	-2,262	-1,639
Property, plant and equipment, net	25,090	25,773
NON-CURRENT ASSETS HELD FOR SALE	145	985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,513	3,502
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	19	42
GOODWILL	5,262	5,606
INTANGIBLE ASSETS, net	1,490	1,561
OTHER NON-CURRENT ASSETS, net	455	357
Total assets	43,556	43,230
CURRENT LIABILITIES:	'	'
Accounts payable	3,357	3,002
Accounts payable to related companies	53	24
Exchanges payable	190	156
Price risk management liabilities	64	110
Accrued and other current liabilities	1,617	1,562
Current maturities of long-term debt	294	609
Current liabilities held for sale	13	85
Total current liabilities	5,588	5,548
NON-CURRENT LIABILITIES HELD FOR SALE	70	142
LONG-TERM DEBT, less current maturities	16,352	15,442
LONG-TERM NOTES PAYABLE — RELATED PARTY	0	166
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	54	129
DEFERRED INCOME TAXES	3,605	3,476
OTHER NON-CURRENT LIABILITIES	948	995
COMMITMENTS AND CONTINGENCIES (Note 12)	'	'
EQUITY:	'	'
General Partner	207	188
Limited Partners:	'	'
Common Unitholders	12,002	9,026
Accumulated other comprehensive income (loss)	3	-13
Total partners’ capital	12,212	9,201
Noncontrolling interest	4,727	8,131
Total equity	16,939	17,332
Total liabilities and equity	$43,556	$43,230

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
REVENUES:	'	'	'	'
Natural gas sales	$721	$655	$2,286	$1,572
NGL sales	708	460	1,885	1,300
Crude sales	4,215	0	11,408	0
Gathering, transportation and other fees	648	530	1,977	1,429
Refined product sales	4,633	0	13,945	0
Other	977	157	2,806	420
Total revenues	11,902	1,802	34,307	4,721
COSTS AND EXPENSES:	'	'	'	'
Cost of products sold	10,654	1,026	30,477	2,606
Operating expenses	331	167	950	493
Depreciation and amortization	253	162	764	419
Selling, general and administrative	138	82	424	272
Total costs and expenses	11,376	1,437	32,615	3,790
OPERATING INCOME	526	365	1,692	931
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense, net of interest capitalized	-210	-147	-632	-479
Equity in earnings of unconsolidated affiliates	28	8	137	64
Gain on deconsolidation of Propane Business	0	0	0	1,057
Gain on sale of AmeriGas common units	87	0	87	0
Loss on extinguishment of debt	0	0	0	-115
Gains (losses) on interest rate derivatives	0	0	46	-9
Other, net	7	7	6	10
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	438	233	1,336	1,459
Income tax expense from continuing operations	47	27	139	36
INCOME FROM CONTINUING OPERATIONS	391	206	1,197	1,423
Income (loss) from discontinued operations	13	-142	44	-136
NET INCOME	404	64	1,241	1,287
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	49	28	244	25
NET INCOME ATTRIBUTABLE TO PARTNERS	355	36	997	1,262
GENERAL PARTNER’S INTEREST IN NET INCOME	146	116	429	342
LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)	$209	($80)	$568	$920
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:	'	'	'	'
Basic	0.51	0.26	1.55	4.54
Diluted	0.51	0.26	1.55	4.52
NET INCOME (LOSS) PER LIMITED PARTNER UNIT:	'	'	'	'
Basic	0.55	-0.33	1.63	3.91
Diluted	0.55	-0.33	1.63	3.89

Consolidated_Statements_Of_Com

Consolidated Statements Of Comprehensive Income (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Other Comprehensive Income [Abstract]	'	'	'	'
Net income	$404	$64	$1,241	$1,287
Other comprehensive income (loss), net of tax:	'	'	'	'
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	-3	-9	-5	-21
Change in value of derivative instruments accounted for as cash flow hedges	-4	-7	4	14
Change in value of available-for-sale securities	1	0	1	0
Actuarial gain relating to pension and other postretirement benefits	8	0	9	0
Foreign currency translation adjustment	0	0	-1	0
Change in other comprehensive income from equity investments	9	8	13	-14
Total other comprehensive income (loss)	11	-8	21	-21
Comprehensive income	415	56	1,262	1,266
Less: Comprehensive income attributable to noncontrolling interest	49	9	241	33
Comprehensive income attributable to partners	$366	$47	$1,021	$1,233

Consolidated_Statement_Of_Equi

Consolidated Statement Of Equity (USD $)	Total	General Partner	Limited Partner Common Unitholders	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
In Millions
Balance, December 31, 2012 at Dec. 31, 2012	$17,332	$188	$9,026	($13)	$8,131
Distributions to partners	-1,341	-410	-931	0	0
Distributions to noncontrolling interest	-309	0	0	0	-309
Units issued for cash	1,301	0	1,301	0	0
Capital contributions from noncontrolling interest	100	0	0	0	100
Holdco Acquisition and SUGS Contribution	-1,437	0	2,013	-5	-3,445
Non-cash compensation expense, net of units tendered by employees for tax withholdings	37	0	28	0	9
Other comprehensive income (loss), net of tax	21	0	0	24	-3
Other, net	-6	0	-3	-3	0
Net Income (Loss) Allocated to General Partners	-429	'	'	'	'
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	1,241	'	568	0	'
Net Income (Loss) Attributable to Noncontrolling Interest	-244	'	'	'	'
Balance, September 30, 2013 at Sep. 30, 2013	$16,939	$207	$12,002	$3	$4,727

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
Net income	$1,241	$1,287
Reconciliation of net income to net cash provided by operating activities:	'	'
Depreciation and amortization	764	419
Deferred income taxes	249	40
Gain on curtailment of other postretirement benefits	0	-15
Amortization of finance costs charged to interest	-63	-9
Loss on extinguishment of debt	0	115
LIFO valuation adjustments	-22	0
Non-cash compensation expense	36	31
Gain on deconsolidation of Propane Business	0	-1,057
Gain on sale of AmeriGas common units	-87	0
Write-down of assets included in loss from discontinued operations	0	145
Distributions on unvested awards	-9	-6
Equity in earnings of unconsolidated affiliates	-137	-64
Distributions from unconsolidated affiliates	220	95
Other non-cash	11	64
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 3)	-461	-133
Net cash provided by operating activities	1,742	912
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Cash paid for Citrus Merger	0	-1,895
Cash proceeds from contribution and sale of propane operations	0	1,443
Cash proceeds from SUGS Contribution	493	0
Cash paid for Holdco Acquisition	-1,332	0
Cash Proceeds from the Sale of MGE Assets	973	0
Cash Proceeds from the Sale of AmeriGas Common Units	346	0
Cash (paid) received from all other acquisitions	-5	471
Capital expenditures (excluding allowance for equity funds used during construction)	-1,840	-1,938
Contributions in aid of construction costs	11	28
Contributions to unconsolidated affiliates	-1	-2
Distributions from unconsolidated affiliates in excess of cumulative earnings	121	95
Proceeds from the sale of assets	37	13
Other	-29	-2
Net cash used in investing activities	-1,226	-1,787
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from borrowings	6,971	5,696
Repayments of long-term debt	-6,312	-4,744
Proceeds from (Repayments of ) Related Party Debt	-166	0
Net proceeds from issuance of Limited Partner units	1,301	772
Capital contributions received from noncontrolling interest	123	240
Distributions to partners	-1,341	-1,020
Distributions to noncontrolling interest	-309	-39
Debt issuance costs	-30	-20
Net cash provided by financing activities	237	885
INCREASE IN CASH AND CASH EQUIVALENTS	753	10
CASH AND CASH EQUIVALENTS, beginning of period	311	107
CASH AND CASH EQUIVALENTS, end of period	$1,064	$117

Operations_And_Organization

Operations And Organization	9 Months Ended
	Sep. 30, 2013
Operations And Organization [Abstract]	'
Operations And Organization	'
	OPERATIONS AND ORGANIZATION:
	Energy Transfer Partners, L.P., a publicly traded Delaware limited partnership, and its subsidiaries (“Energy Transfer Partners,” the “Partnership,” “we” or “ETP”) are managed by ETP’s general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner. The consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below.
	Business Operations
	Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows:
	•	ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.
	•	ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:
	•	Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
	•	ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.
	•	ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.
	•	CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.
	•	ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.
	•	Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products and crude oil pipelines, terminalling and storage assets, and refined products and crude oil acquisition and marketing assets.
	•	Holdco, a Delaware limited liability company that indirectly owns Southern Union and Sunoco. As discussed in Note 2, ETP acquired ETE’s 60% interest in Holdco on April 30, 2013. Sunoco and Southern Union operations are described as follows:
	•	Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation, storage and distribution of natural gas in the United States. As discussed in Note 2, on April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interests in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. Additionally, as discussed in Note 2, on September 1, 2013, Southern Union completed its sale of the assets of MGE to Laclede Gas Company.
	•	Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail and operates convenience stores primarily on the east coast and in the midwest region of the United States.
	Our financial statements reflect the following reportable business segments:
	•intrastate natural gas transportation and storage;
	•interstate natural gas transportation and storage;
	•midstream;
	•NGL transportation and services;
	•investment in Sunoco Logistics; and
	•retail marketing.
	Preparation of Interim Financial Statements
	The accompanying consolidated balance sheet as of December 31, 2012, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership as of September 30, 2013 and for the three and nine month periods ended September 30, 2013 and 2012, have been prepared in accordance with GAAP for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting.
	In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of September 30, 2013, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2013 and 2012. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Partners presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012, as filed with the SEC on March 1, 2013.
	Certain prior period amounts have been reclassified to conform to the 2013 presentation. These reclassifications had no impact on net income or total equity.
	In accordance with GAAP, we have accounted for the October 2012 transaction in which ETE contributed its interest in Southern Union to Holdco in exchange for a 60% interest in Holdco and ETP contributed its interest in Sunoco (exclusive of Sunoco Logistics) to Holdco in exchange for a 40% interest in Holdco (the “Holdco Transaction”) as a reorganization of entities under common control. Accordingly, ETP's consolidated financial statements have been retrospectively adjusted to reflect the consolidation of Southern Union into ETP beginning March 26, 2012 (the date ETE acquired Southern Union).

Acquisitions_Divestitures_and_

Acquisitions, Divestitures and Related Transactions	9 Months Ended
	Sep. 30, 2013
Acquisitions and Dispositions [Abstract]	'
Acquisitions And Divestitures	'
	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
	Sale of Distribution Operations
	In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union’s NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allows a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division, subject to certain approvals.
	Effective September 1, 2013, Southern Union completed its sale of the assets of MGE to Laclede Gas Company for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. The sale of Southern Union’s NEG division is expected to close in the fourth quarter of 2013 for cash proceeds of $40 million, subject to customary post-closing adjustments, and the assumption of $20 million of debt.
	The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations. The assets and liabilities of the LDC Disposal Group have been classified as assets and liabilities held for sale.
	SUGS Contribution
	On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings, a wholly-owned subsidiary of Southern Union, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Partnership has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency common and Class F units received, which has been accounted for using the equity method.
	Acquisition of ETE’s Holdco Interest
	On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “Holdco Acquisition”). As a result, ETP now owns 100% of Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.
	Sunoco Merger
	On October 5, 2012, Sam Acquisition Corporation, a Pennsylvania corporation and a wholly-owned subsidiary of ETP, completed its merger with Sunoco (the “Sunoco Merger”). Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and $2.6 billion in cash.

Cash_And_Cash_Equivalents

Cash And Cash Equivalents	9 Months Ended
	Sep. 30, 2013
Cash and Cash Equivalents [Abstract]	'
Cash And Cash Equivalents	'
	CASH AND CASH EQUIVALENTS:
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
	The net change in operating assets and liabilities included in cash flows from operating activities is comprised as follows:
		Nine Months Ended
		September 30,
		2013			2012
	Accounts receivable	$	(392	)	$	(67	)
	Accounts receivable from related companies	(50		)	(44		)
	Inventories	(132		)	(56		)
	Exchanges receivable	—			22
	Other current assets	(186		)	67
	Other non-current assets, net	(29		)	(32		)
	Accounts payable	398			43
	Accounts payable to related companies	(67		)	99
	Exchanges payable	36			(24		)
	Accrued and other current liabilities	92			(154		)
	Other non-current liabilities	(15		)	(3		)
	Price risk management assets and liabilities, net	(116		)	16
	Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(461	)	$	(133	)
	Non-cash investing and financing activities are as follows:
		Nine Months Ended
		September 30,
		2013			2012
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	190		$	391
	AmeriGas limited partner interests received in exchange for contribution of Propane Business	$	—		$	1,123
	Regency common and Class F units received in exchange for contribution of SUGS	$	961		$	—
	NON-CASH FINANCING ACTIVITIES:
	Contributions receivable related to noncontrolling interest	$	—		$	13
	Issuance of common units in connection with acquisitions	$	—		$	112
	Issuance of common units in connection with the Holdco Acquisition	$	2,464		$	—

Inventories

Inventories	9 Months Ended
	Sep. 30, 2013
Inventory, Gross [Abstract]	'
Inventories	'
	INVENTORIES:
	Inventories consisted of the following:
		September 30, 2013		December 31, 2012
	Natural gas and NGLs	$	509	$	334
	Crude oil	464		418
	Refined products	517		572
	Appliances, parts and fittings and other	167		171
	Total inventories	$	1,657	$	1,495
	We utilize commodity derivatives to manage price volatility associated with our natural gas inventory and designate certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2013
Fair Value Measurements [Abstract]	'
Fair Value Measurements	'
	FAIR VALUE MEASUREMENTS:
	We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of 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. We currently do not have any recurring fair value measurements that are considered Level 3 valuations. During the nine months ended September 30, 2013, no transfers were made between any levels within the fair value hierarchy.
	Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations at September 30, 2013 and December 31, 2012 was $17.16 billion and $17.84 billion, respectively. As of September 30, 2013 and December 31, 2012, the aggregate carrying amount of our consolidated debt obligations was $16.65 billion and $16.22 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
	The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2013 and December 31, 2012 based on inputs used to derive their fair values:
					Fair Value Measurements at September 30, 2013
		Fair Value Total			Level 1			Level 2
	Assets:
	Interest rate derivatives	$	43		$	—		$	43
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	4			4			—
	Swing Swaps IFERC	1			—			1
	Fixed Swaps/Futures	84			84			—
	Options — Calls	1			—			1
	Forward Physical Swaps	1			—			1
	Power — Forwards	2			—			2
	Natural Gas Liquids — Forwards/Swaps	9			9			—
	Refined Products — Futures	25			25			—
	Total commodity derivatives	127			122			5
	Total Assets	$	170		$	122		$	48
	Liabilities:
	Interest rate derivatives	$	(111	)	$	—		$	(111	)
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(8		)	(8		)	—
	Swing Swaps IFERC	(2		)	—			(2		)
	Fixed Swaps/Futures	(58		)	(58		)	—
	Options — Calls	(1		)	—			(1		)
	Power:
	Forwards	(1		)	—			(1		)
	Options — Calls	(2		)	—			(2		)
	Natural Gas Liquids — Forwards/Swaps	(8		)	(8		)	—
	Refined Products — Futures	(16		)	(16		)	—
	Crude — Futures	(2		)	(2		)	—
	Total commodity derivatives	(98		)	(92		)	(6		)
	Total Liabilities	$	(209	)	$	(92	)	$	(117	)
					Fair Value Measurements at December 31, 2012
		Fair Value Total			Level 1			Level 2
	Assets:
	Interest rate derivatives	$	55		$	—		$	55
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	11			11			—
	Swing Swaps IFERC	3			—			3
	Fixed Swaps/Futures	96			94			2
	Options — Puts	1			—			1
	Options — Calls	3			—			3
	Forward Physical Swaps	1			—			1
	Power:
	Forwards	27			—			27
	Futures	1			1			—
	Options — Calls	2			—			2
	Natural Gas Liquids — Swaps	1			1			—
	Refined Products — Futures	5			1			4
	Total commodity derivatives	151			108			43
	Total Assets	$	206		$	108		$	98
	Liabilities:
	Interest rate derivatives	$	(223	)	$	—		$	(223	)
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(18		)	(18		)	—
	Swing Swaps IFERC	(2		)	—			(2		)
	Fixed Swaps/Futures	(103		)	(94		)	(9		)
Options — Puts	(1		)	—			(1		)
Options — Calls	(3		)	—			(3		)
Power:
Forwards	(27		)	—			(27		)
Futures	(2		)	(2		)	—
Natural Gas Liquids — Swaps	(3		)	(3		)	—
Refined Products — Futures	(8		)	(1		)	(7		)
Total commodity derivatives	(167		)	(118		)	(49		)
Total Liabilities	$	(390	)	$	(118	)	$	(272	)

Net_Income_Per_Limited_Partner

Net Income Per Limited Partner Unit	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Earnings Per Share [Text Block]	'
	NET INCOME PER LIMITED PARTNER UNIT:
	Our net income for partners’ capital and statements of operations presentation purposes is allocated to ETP GP and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to ETP GP, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to ETP GP and Limited Partners based on their respective ownership interests.
	A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows:
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013			2012
	Income from continuing operations	$	391		$	206		$	1,197		$	1,423
	Less: Income from continuing operations attributable to noncontrolling interest	49			22			227			10
	Income from continuing operations, net of noncontrolling interest	342			184			970			1,413
	General Partner’s interest in income from continuing operations	146			119			428			344
	Limited Partners’ interest in income from continuing operations	196			65			542			1,069
	Additional earnings allocated from (to) General Partner	—			1			(1		)	1
	Distributions on employee unit awards, net of allocation to General Partner	(3		)	(2		)	(8		)	(9		)
	Income from continuing operations available to Limited Partners	$	193		$	64		$	533		$	1,061
	Weighted average Limited Partner units – basic	374.1			245.1			342.8			233.8
	Basic income from continuing operations per Limited Partner unit	$	0.51		$	0.26		$	1.55		$	4.54
	Dilutive effect of unvested Unit Awards	1.4			1.2			1.3			1.2
	Weighted average Limited Partner units, assuming dilutive effect of unvested Unit Awards	375.5			246.3			344.1			235
	Diluted income from continuing operations per Limited Partner unit	$	0.51		$	0.26		$	1.55		$	4.52
	Basic income (loss) from discontinued operations per Limited Partner unit	$	0.04		$	(0.59	)	$	0.08		$	(0.63	)
	Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.04		$	(0.59	)	$	0.08		$	(0.63	)

Debt_Obligations

Debt Obligations	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Debt Obligations	'
	DEBT OBLIGATIONS:
	Senior Notes
	In January 2013, ETP issued $800 million aggregate principal amount of 3.6% Senior Notes due February 2023 and $450 million aggregate principal amount of 5.15% Senior Notes due February 2043. ETP used the net proceeds of $1.24 billion from the offering to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.
	In January 2013, Sunoco Logistics issued $350 million aggregate principal amount of 3.45% Senior Notes due January 2023 and $350 million aggregate principal amount of 4.95% Senior Notes due January 2043. The net proceeds of $691 million from the offering were used to pay outstanding borrowings under the Sunoco Logistics’ Credit Facilities and for general partnership purposes.
	In September 2013, ETP issued $700 million aggregate principal amount of 4.15% Senior Notes due October 2020, $350 million aggregate principal amount of 4.90% Senior Notes due February 2024 and $450 million aggregate principal amount of 5.95% Senior Notes due October 2043. ETP used the net proceeds of $1.47 billion from the offering to repay $455 million in borrowings outstanding under the term loan of Panhandle’s wholly-owned subsidiary, Trunkline LNG Holdings, LLC, to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.
	Note Exchange
	On June 24, 2013, ETP completed the exchange of approximately $1.09 billion aggregate principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066.  These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates.  In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes.
	Credit Facilities
	ETP Credit Facility
	ETP has a $2.5 billion revolving credit facility which expires in October 2016. Indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The ETP Credit Facility had no outstanding borrowings as of September 30, 2013.
	Southern Union Credit Facility
	Proceeds from the SUGS Contribution were used to repay $240 million of borrowings under the Eighth Amended and Restated Revolving Credit Agreement (the “Southern Union Credit Facility”) and the facility was terminated.
	Sunoco Logistics Credit Facilities
	Sunoco Logistics maintains two credit facilities to fund its working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 and a $200 million unsecured credit facility which expires in August 2014. There were no outstanding borrowings under these credit facilities as of September 30, 2013.
	West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, has a $35 million revolving credit facility which expires in April 2015. Outstanding borrowings under this credit facility were $35 million as of September 30, 2013.
	Compliance with Our Covenants
	We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, 2013.

Equity

Equity	9 Months Ended
	Sep. 30, 2013
Partners' Capital Notes [Abstract]	'
Equity	'
	EQUITY:
	Class G Units
	In April 2013, all of the outstanding ETP Class F Units, which were issued in connection with the Sunoco Merger, were exchanged for ETP Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in the consolidated financial statements.
	Class H Units
	Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Common Holdings, LLC, a wholly owned subsidiary of ETE (“ETE Holdings”), ETP redeemed and cancelled 50.2 million of its common units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners LLC (“Sunoco Partners”), the general partner of Sunoco Logistics, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters and (iii) incremental additional cash distributions in the aggregate amount of $329 million, to be payable by ETP to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017. The incremental cash distributions referred to in clause (iii) of the previous sentence are intended to offset a portion of the IDR subsidies previously granted by ETE to ETP in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. In connection with the issuance of the Class H Units, ETE and ETP also agreed to certain adjustments to the prior IDR subsidies in order to ensure that the IDR subsidies are fixed amounts for each quarter to which the IDR subsidies are in effect. For a summary of the net IDR subsidy amounts resulting from this transaction, see “Quarterly Distributions of Available Cash” below.
	Common Unit Activity
	The change in Common Units during the nine months ended September 30, 2013 was as follows:
		Number of Units
	Outstanding at December 31, 2012	301.5
	Common Units issued in connection with public offerings	13.8
	Common Units issued in connection with Equity Distribution Agreements	11.6
	Common Units issued in connection with the Distribution Reinvestment Plan	1.6
	Common Units issued in connection with the Holdco Acquisition	49.5
	Outstanding at September 30, 2013	378
	In January 2013 and May 2013, we entered into Equity Distribution Agreements pursuant to which we may sell from time to time Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. During the nine months ended September 30, 2013, we received proceeds of $568 million, net of commissions of $6 million, from the issuance of units pursuant to the Equity Distribution Agreements, which proceeds were used for general partnership purposes. We also received $13 million, net of commissions, in October 2013 from the settlement of transactions initiated in September 2013 under these agreements. Approximately $426 million of our Common Units remain available to be issued under these agreements.
	During the nine months ended September 30, 2013, distributions of $76 million were reinvested under the Distribution Reinvestment Plan resulting in the issuance of 1.6 million Common Units. As of September 30, 2013, a total of 2.7 million Common Units remain available to be issued under the existing registration statement.
	In April 2013, we issued 13.8 million Common Units at $48.05 per Common Unit in an underwritten public offering. Net proceeds of $657 million from the offering were used to repay amounts outstanding under the ETP Credit Facility and for general partnership purposes.
	As discussed in “Class H Units” above ETP redeemed and cancelled 50.2 million of its Common Units in connection with the issuance of Class H Units to ETE.
	Quarterly Distributions of Available Cash
	Following are distributions declared and/or paid by ETP subsequent to December 31, 2012:
	Quarter Ended		Record Date		Payment Date		Rate
	December 31, 2012		February 7, 2013		February 14, 2013		$	0.89375
	March 31, 2013		May 6, 2013		May 15, 2013		0.89375
	June 30, 2013		August 5, 2013		14-Aug-13		0.89375
	September 30, 2013		November 4, 2013		14-Nov-13		0.905
	Following are incentive distributions ETE has agreed to relinquish:
	•	In conjunction with the Partnership’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012.
	•	In conjunction with the Holdco Transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.
	•	As discussed in Note 2, in connection with the Holdco Acquisition on April 30, 2013, ETE also agreed to relinquish incentive distributions on the newly issued Common Units for the first eight consecutive quarters beginning with the distribution paid on August 14, 2013, and 50% of the incentive distributions for the following eight consecutive quarters.
	•	As discussed under “Class H Units” above, ETP has agreed to make incremental cash distributions in the aggregate amount of $329 million to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017, in respect of the Class H units as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition.
	As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:
			Quarters Ending
			31-Mar				30-Jun		30-Sep		31-Dec		Total Year
	2013		N/A				N/A		$	21	$	21	$	42
	2014		$	27.25			$	27.25	27.25		27.25		109
	2015		13.25				13.25		13.25		13.25		53
	2016		5.5				5.5		5.5		5.5		22
	Sunoco Logistics Quarterly Distributions of Available Cash
	Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:
	Quarter Ended		Record Date		Payment Date		Rate
	December 31, 2012		February 8, 2013		February 14, 2013		$	0.545
	March 31, 2013		May 9, 2013		May 15, 2013		0.5725
	June 30, 2013		8-Aug-13		14-Aug-13		0.6
	September 30, 2013		8-Nov-13		14-Nov-13		0.63
	Accumulated Other Comprehensive Income (Loss)
	The following table presents the components of accumulated other comprehensive income (loss), net of tax:
		September 30, 2013				December 31, 2012
	Available-for-sale securities	$	1			$	—
	Foreign currency translation adjustment	(1		)		—
	Actuarial loss related to pensions and other postretirement benefits	(1		)		(10		)
	Equity investments, net	4				(9		)
	Subtotal	3				(19		)
	Amounts attributable to noncontrolling interest	—				6
	Total accumulated other comprehensive income (loss), net of tax	$	3			$	(13	)

UnitBased_Compensation_Plans

Unit-Based Compensation Plans	9 Months Ended
	Sep. 30, 2013
Deferred Compensation Arrangements [Abstract]	'
Unit-Based Compensation Plans	'
	UNIT-BASED COMPENSATION PLANS:
	ETP Unit-Based Compensation Plans
	During the nine months ended September 30, 2013, employees were granted a total of 1,142,663 unvested awards with five-year service vesting requirements, and directors were granted a total of 9,060 unvested awards with three-year and five-year service vesting requirements. The weighted average grant-date fair value of these awards was $45.74 per unit. As of September 30, 2013, a total of 2,840,725 unit awards remain unvested, for which we expect to recognize $72 million in compensation expense over a weighted average period of 1.8 years related to unvested awards.
	Sunoco Logistics’ Unit-Based Compensation Plan
	As of September 30, 2013, a total of 918,031 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $16 million in compensation expense over a weighted-average period of 2.4 years.

Income_Tax_Notes

Income Tax (Notes)	9 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]	'
Income Tax Disclosure [Text Block]	'
	INCOME TAXES:
	The follow table summarizes the Partnership’s income tax expense from continuing operations:
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013			2012
	Income tax expense from continuing operations	$	47		$	27		$	139		$	36
	Effective tax rate	11		%	12		%	10		%	2		%
	The increase in the effective tax rate for the nine months ended September 30, 2013 compared to the same period last year is primarily due to the Partnership conducting a significant portion of its activities through its corporate subsidiaries, Southern Union and Sunoco, as a result of the Holdco Transaction and Sunoco Merger completed in 2012.
	Sunoco has historically included certain government incentive payments as taxable income on its federal and state income tax returns.  In connection with Sunoco’s 2004 through 2011 open statute years, Sunoco has proposed to the Internal Revenue Service (“IRS”) that these government incentive payments be excluded from federal taxable income. A successful claim could result in significant tax refunds for multiple years. However, a thorough evaluation of the ultimate financial impact to Sunoco is complex and requires significant analysis, including the ramifications of tax indemnification agreements with certain former Sunoco affiliates which were members of Sunoco’s consolidated federal return group during these years. At this time, a benefit for the claim is not estimable and has not been recorded in the financial statements.

Retirement_Benefits_Notes

Retirement Benefits (Notes)	9 Months Ended
	Sep. 30, 2013
Retirement Benefits [Abstract]	'
Pension and Other Postretirement Benefits Disclosure [Text Block]	'
	RETIREMENT BENEFITS:
	The following tables set forth the components of net period benefit cost of the Partnership’s pension and other postretirement benefit plans:
		Three Months Ended September 30,
		2013						2012(1)
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
	Net Periodic Benefit Cost:
	Service cost	$	—		$	(1	)	$	1		$	—
	Interest cost	10			2			2			1
	Expected return on plan assets	(15		)	(3		)	(3		)	(2		)
	Prior service cost amortization	—			1			—			—
	Actuarial loss amortization	1			—			—			—
		(4		)	(1		)	—			(1		)
	Regulatory adjustment(2)	1			—			3			1
	Net periodic benefit cost	$	(3	)	$	(1	)	$	3		$	—
		Nine Months Ended September 30,
		2013						2012(1)
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
	Net Periodic Benefit Cost:
	Service cost	$	5		$	—		$	2		$	—
	Interest cost	28			5			5			1
	Expected return on plan assets	(45		)	(7		)	(6		)	(3		)
	Prior service cost amortization	—			1			—			—
	Actuarial loss amortization	2			—			—			—
	Settlement credits	(2		)	—			—			—
	Curtailment recognition(3)	—			—			—			(15		)
		(12		)	(1		)	1			(17		)
	Regulatory adjustment(2)	5			—			6			1
	Net periodic benefit cost	$	(7	)	$	(1	)	$	7		$	(16	)
	(1)	The three and nine months ended September 30, 2012 include components of net periodic benefit cost of Southern Union subsequent to the Southern Union Merger on March 26, 2012.
	(2)	Southern Union has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its MGE and NEG divisions.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.
	(3)	Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million.  Such gain was offset by establishment of a non-current refund liability in the amount of $60 million.  As such, the net curtailment gain recognition was $15 million.

Regulatory_Matters_Commitments

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	9 Months Ended
	Sep. 30, 2013
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]	'
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	'
	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
	FERC Audit
	The FERC recently completed an audit of PEPL, a subsidiary of Southern Union, for the period from January 1, 2010 through December 31, 2011, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. An audit report was received in August 2013 noting no issues that would have a material impact on the Partnership’s historical financial position or results of operations.
	Contingent Residual Support Agreement — AmeriGas
	In connection with the closing of the contribution of its propane operations in January 2013, ETP agreed to provide contingent, residual support of $1.55 billion of senior notes issued by AmeriGas and certain of its affiliates with maturities through 2022.
	PEPL Holdings Guarantee of Collection
	In connection with the SUGS Contribution, Regency issued $600 million of 4.50% Senior Notes due 2023 (the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023.
	Commitments
	In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.
	We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled $31 million and $12 million for the three months ended September 30, 2013 and 2012, respectively, which include contingent rentals totaling $8 million in the three months ended September 30, 2013. For the nine months ended September 30, 2013 and 2012, rental expense for operating leases totaled $93 million and $29 million, respectively, which include contingent rentals totaling $18 million in the nine months ended September 30, 2013. During the three and nine months ended September 30, 2013, $6 million and $16 million, respectively, of rental expense was recovered through related sublease rental income.
	Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
	Litigation and Contingencies
	We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude 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.
	Sunoco Litigation
	Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania.  Each complaint names as defendants the members of Sunoco’s board of directors and alleges that they breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco’s directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the Sunoco Merger. Subsequent to the settlement of these cases, the plaintiffs’ attorneys sought compensation from Sunoco for attorneys’ fees related to their efforts in obtaining these additional disclosures. In January 2013, Sunoco entered into agreements to compensate the plaintiffs’ attorneys in the state court actions in the aggregate amount of not more than $950,000 and to compensate the plaintiffs’ attorneys in the federal court action in the amount of not more than $250,000. The payment of $950,000 was made in July 2013.
	Litigation Relating to the Southern Union Merger
	In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21, 2011, the court denied ETE’s October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.
	Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.
	On September 18, 2013, the plaintiff dismissed without prejudice its lawsuit against all defendants.
	MTBE Litigation
	Sunoco, along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases, injunctive relief, punitive damages and attorneys’ fees.
	As of September 30, 2013, Sunoco is a defendant in six cases, including one initiated by the State of New Jersey and another by the Commonwealth of Puerto Rico. These cases are venued in a multidistrict proceeding in a New York federal court. The two state cases assert natural resource damage claims. In addition, Sunoco has received notice from another state that it intends to file an MTBE lawsuit in the near future asserting natural resource damage claims.
	Discovery is proceeding in these cases. There has been insufficient information developed about the plaintiffs’ legal theories or the facts in the natural resource damage claims that would be relevant to an analysis of the ultimate liability of Sunoco in these matters; however, it is reasonably possible that a loss may be realized. 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 the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.
	Other Litigation and Contingencies
	In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union. The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas. Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants. Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union. On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action. On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment. Defendants filed a reply on December 19, 2012. On December 20, 2012, the court conducted an oral hearing on the motion. Plaintiffs filed a post-hearing sur-reply on January 7, 2013. On January 16, 2013, the Court granted defendants’ motion for summary judgment. The parties agreed to settle the matter and executed a memorandum of understanding. On October 4, 2013, the Court approved the settlement and ordered the case dismissed with prejudice.
	We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2013 and December 31, 2012, accruals of approximately $38 million and $42 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.
	No amounts have been recorded in our September 30, 2013 or December 31, 2012 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
	Litigation Related to Incident at JJ's Restaurant.  On February 19, 2013, there was a natural gas explosion at JJ's Restaurant located at 910 W. 48th Street in Kansas City, Missouri.  Effective September 1, 2013, Laclede Gas Company, a subsidiary of The Laclede Group, Inc. (“Laclede”), assumed any and all liability arising from this incident in ETP’s sale of the assets of MGE to Laclede.
	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 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 $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. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union 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.
	•	Southern Union’s distribution operations are responsible for soil and groundwater remediation at certain sites related to manufactured gas plants (“MGPs”) and may also be responsible for the removal of old MGP structures.
	•	Currently operating Sunoco retail sites.
	•	Legacy sites related to Sunoco, that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.
	•	Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of September 30, 2013, Sunoco had been named as a PRP at 39 identified or potentially identifiable as “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
	To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
	The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
		September 30, 2013		December 31, 2012
	Current	$	38	$	46
	Non-current	185		165
	Total environmental liabilities	$	223	$	211
	During the three and nine months ended September 30, 2013, Sunoco recorded $8 million and $23 million, respectively, of expenditures related to environmental cleanup programs.
	The EPA’s Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities. We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.
	On August 20, 2010, the EPA published new regulations under the federal Clean Air Act (“CAA”) to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations. Compliance with the final rule was required by October 2013, and the Partnership believes it is in compliance.
	On June 29, 2011, the EPA finalized a rule under the CAA 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 DOT under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
	Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Price_Risk_Management_Assets_A

Price Risk Management Assets And Liabilities	9 Months Ended
	Sep. 30, 2013
General Discussion of Derivative Instruments and Hedging Activities [Abstract]	'
Price Risk Management Assets and Liabilities	'
	PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
	Commodity Price Risk
	We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
	We inject and hold natural gas in our Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.
	We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. We use financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	We are also exposed to commodity price risk on NGLs and residue gas we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, we also have trading activities related to power in our “All Other” segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
	Derivatives are utilized in our midstream segment in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist.
	The following table details our outstanding commodity-related derivatives:
		September 30, 2013					December 31, 2012
		Notional Volume			Maturity		Notional Volume			Maturity
	Mark-to-Market Derivatives
	(Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	6,560,000			2013-2019		—			—
	Basis Swaps IFERC/NYMEX(1)	(27,402,500	)		2013-2017		(30,980,000	)		2013-2014
	Swing Swaps	1,690,000			2013-2016		—			—
	Power (Megawatt):
	Forwards	562,250			2013		19,650			2013
	Futures	97,212			2013		(1,509,300	)		2013
	Options — Calls	(1,700	)		2013		1,656,400			2013
	Crude (Bbls) — Futures	80,000			2013		—			—
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(5,300,000	)		2013-2014		150,000			2013
	Swing Swaps IFERC	6,965,000			2013-2016		(83,292,500	)		2013
	Fixed Swaps/Futures	(14,072,500	)		2013-2015		27,077,500			2013
	Forward Physical Contracts	(11,663,485	)		2013-2014		11,689,855			2013-2014
	Natural Gas Liquid (Bbls) — Forwards/Swaps	(1,182,000	)		2013-2014		(30,000	)		2013
	Refined Products (Bbls) — Futures	(93,327	)		2013-2014		(666,000	)		2013
	Fair Value Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(6,577,500	)		2013		(18,655,000	)		2013
	Fixed Swaps/Futures	(47,215,000	)		2014		(44,272,500	)		2013
	Hedged Item — Inventory	47,215,000			2014		44,272,500			2013
	Cash Flow Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(1,150,000	)		2013		—			—
	Fixed Swaps/Futures	(5,720,000	)		2013		(8,212,500	)		2013
	Natural Gas Liquid (Bbls) — Forwards/Swaps	(720,000	)		2013		(930,000	)		2013
	Refined Products (Bbls) — Futures	—			—		(98,000	)		2013
	Crude (Bbls) — Futures	(120,000	)		2013		—			—
	(1)	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
	We expect gains of $1 million related to commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.
	Interest Rate Risk
	We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
	The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
	Entity		Term		Type(1)		Notional Amount Outstanding
							September 30, 2013				December 31, 2012
	ETP		July 2013(2)		Forward-starting to pay a fixed rate of 4.03% and receive a floating rate		$	—			$	400
	ETP		July 2014(2)		Forward-starting to pay a fixed rate of 4.25% and receive a floating rate		400				400
	ETP		Jul-18		Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		600				600
	ETP		Jun-21		Pay a floating rate plus a spread of 2.15% and receive a fixed rate of 4.65%		200				—
	ETP		Feb-23		Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%		400				—
	Southern Union		Nov-16		Pay a fixed rate of 2.97% and receive a floating rate		25				75
	Southern Union		Nov-21		Pay a fixed rate of 3.75% and receive a floating rate		450				450
	(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. During the nine months ended September 30, 2013, we settled $400 million of ETP’s forward-starting interest rate swaps that had an effective date of July 2013.
	Credit Risk
	We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single or multiple counterparties.
	Our counterparties consist of a diverse portfolio of customers across the energy industry including petrochemical companies, consumer and industrials, oil and gas producers, municipalities, utilities and midstream companies. Our overall exposure to credit risk may be affected either positively or negatively in that the counterparties may experience similar changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.
We utilize master-netting agreements and have maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
	Fair Value of Derivative Instruments
	Asset Derivatives								Liability Derivatives
	September 30, 2013				December 31, 2012				September 30, 2013				December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	16			$	8			$	(3	)		$	(10	)
	16				8				(3		)		(10		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	112				110				(95		)		(116		)
Commodity derivatives	32				33				(33		)		(34		)
Current assets held for sale	—				1				—				—
Non-current assets held for sale	—				1				—				—
Current liabilities held for sale	—				—				—				(9		)
Interest rate derivatives	43				55				(111		)		(223		)
	187				200				(239		)		(382		)
Total derivatives	$	203			$	208			$	(242	)		$	(392	)
In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
				Asset Derivatives								Liability Derivatives
		Balance Sheet Location		September 30, 2013				December 31, 2012				September 30, 2013				December 31, 2012
Derivatives in offsetting agreements:
OTC contracts		Price risk management assets (liabilities)		$	37			$	28			$	(38	)		$	(27	)
Broker cleared derivative contracts		Other current assets (liabilities)		170				150				(159		)		(228		)
				207				178				(197		)		(255		)
Offsetting agreements:
Collateral paid to OTC counterparties		Other current assets		—				—				—				2
Counterparty netting		Price risk management assets (liabilities)		(32		)		(25		)		32				25
Payments on margin deposit		Other current assets		(15		)		—				34				59
				(47		)		(25		)		66				86
Net derivatives with offsetting agreements				160				153				(131		)		(169		)
Derivatives without offsetting agreements				43				55				(111		)		(223		)
Total derivatives				$	203			$	208			$	(242	)		$	(392	)
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 September 30,								Nine Months Ended
										September 30,
		2013				2012				2013				2012
Derivatives in cash flow hedging relationships:
Commodity derivatives		$	(4	)		$	(7	)		$	4			$	14
Total		$	(4	)		$	(7	)		$	4			$	14
	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 September 30,								Nine Months Ended
											September 30,
			2013				2012				2013				2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold		$	3			$	9			$	5			$	21
Total			$	3			$	9			$	5			$	21
	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 September 30,								Nine Months Ended
											September 30,
			2013				2012				2013				2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold		$	—			$	4			$	4			$	29
Total			$	—			$	4			$	4			$	29
	Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain/(Loss) Recognized in Income on Derivatives
			Three Months Ended September 30,								Nine Months Ended
											September 30,
			2013				2012				2013				2012
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold		$	(11	)		$	4			$	(12	)		$	(7	)
Commodity derivatives – Non-Trading	Cost of products sold		(23		)		(5		)		(20		)		(13		)
Commodity derivatives – Non-Trading	Deferred gas purchases		—				—				(3		)		—
Interest rate derivatives	Gains (losses) on interest rate derivatives		—				—				46				(9		)
Total			$	(34	)		$	(1	)		$	11			$	(29	)

Related_Party_Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	RELATED PARTY TRANSACTIONS:
	ETE has agreements with subsidiaries to provide or receive various general and administrative services. ETE pays us to provide services on its behalf and on behalf of other subsidiaries of ETE, which includes the reimbursement of various general and administrative services for expenses incurred by us on behalf of Regency.
	In the ordinary course of business, we provide Regency with certain natural gas and NGLs sales and transportation services and compression equipment, and Regency provides us with certain contract compression services. These related party transactions are generally based on transactions made at market-related rates.
	Sunoco Logistics has an agreement with PES relating to the Fort Mifflin Terminal Complex. Under this agreement, PES will deliver an average of 300,000 Bbls/d of crude oil and refined products per contract year at the Fort Mifflin facility. PES does not have exclusive use of the Fort Mifflin Terminal Complex; however, Sunoco Logistics is obligated to provide the necessary tanks, marine docks and pipelines for PES to meet its minimum requirements under the agreement. Sunoco Logistics executed a 10-year agreement with PES in September 2012.
	In September 2012, Sunoco assigned its lease for the use of Sunoco Logistics’ inter-refinery pipelines between the Philadelphia and Marcus Hook refineries to PES. Under the 20-year lease agreement which expires in February 2022, PES leases the inter-refinery pipelines for an annual fee which escalates at 1.67% each January 1 for the term of the agreement. The lease agreement also requires PES to reimburse Sunoco Logistics for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. There were no material reimbursements under this agreement during 2010 through 2012.
	The following table summarizes the affiliate revenue on our consolidated statements of operations:
		Three Months Ended September 30,				Nine Months Ended
						September 30,
		2013		2012		2013		2012
	Affiliated revenue	$	439	$	20	$	1,154	$	37
	The following table summarizes the related company balances on our consolidated balance sheets:
		September 30, 2013		December 31, 2012
	Accounts receivable from related companies:
	ETE	$	29	$	16
	Regency	75		10
	PES	20		60
	FGT	19		2
	Other	34		6
	Total accounts receivable from related companies:	$	177	$	94
	Accounts payable to related companies:
	ETE	$	8	$	7
	Regency	35		2
	PES	4		13
	FGT	3		—
	Other	3		2
	Total accounts payable to related companies:	$	53	$	24

Other_Information

Other Information	9 Months Ended
	Sep. 30, 2013
Other Information [Abstract]	'
Other Information	'
	OTHER INFORMATION:
	The following tables present additional detail for certain balance sheet captions.
	Other Current Assets
	Other current assets consisted of the following:
		September 30, 2013		December 31, 2012
	Deposits paid to vendors	$	55	$	41
	Prepaid expenses and other	263		293
	Total other current assets	$	318	$	334
	Accrued and Other Current Liabilities
	Accrued and other current liabilities consisted of the following:
		September 30, 2013		December 31, 2012
	Interest payable	$	232	$	256
	Customer advances and deposits	55		44
	Accrued capital expenditures	187		356
	Accrued wages and benefits	181		236
	Taxes payable other than income taxes	276		203
	Income taxes payable	82		40
	Deferred income taxes	243		130
	Deferred revenue	2		—
	Other	359		297
	Total accrued and other current liabilities	$	1,617	$	1,562

Reportable_Segments

Reportable Segments	9 Months Ended
	Sep. 30, 2013
Reportable Segments [Abstract]	'
Reportable Segments	'
	REPORTABLE SEGMENTS:
	As a result of the Sunoco Merger and Holdco Transaction, our reportable segments were re-evaluated and changed in 2012. Our financial statements currently reflect six reportable segments, which conduct their business exclusively in the United States, as follows:
	•intrastate natural gas transportation and storage;
	•interstate natural gas transportation and storage;
	•midstream;
	•NGL transportation and services;
	•investment in Sunoco Logistics;
	•retail marketing; and
	•all other.
	Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
	Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in Sunoco Logistics segment are primarily reflected in crude sales. Revenues from our retail marketing segment are primarily reflected in refined product sales.
	We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes 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. Previously, amounts for less than wholly owned subsidiaries were reflected in Segment Adjusted EBITDA based on the Partnership’s proportionate ownership, such that the measure was reduced for amounts attributable to noncontrolling interests. During the three months ended December 31, 2012, management changed its definition of Segment Adjusted EBITDA to reflect amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. Management believes that the revised segment performance measure more closely reflects the presentation of less than wholly owned subsidiaries within the Partnership’s consolidated financial statements. For periods prior to the three months ended December 31, 2012, only the NGL transportation and services segment included a less than wholly owned subsidiary. Based on this change in our definition of Segment Adjusted EBITDA, we have recast the presentation of our segment results for 2012 to be consistent with the current year presentation.
	The following tables present the financial information by segment:
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013			2012
	Revenues:
	Intrastate transportation and storage:
	Revenues from external customers	$	502		$	503		$	1,711		$	1,402
	Intersegment revenues	51			53			155			130
		553			556			1,866			1,532
	Interstate transportation and storage:
	Revenues from external customers	296			309			973			761
	Intersegment revenues	15			12			19			14
		311			321			992			775
	Midstream:
	Revenues from external customers	683			757			2,021			1,845
	Intersegment revenues	256			107			775			309
		939			864			2,796			2,154
	NGL transportation and services:
	Revenues from external customers	537			157			1,303			459
	Intersegment revenues	11			11			48			37
		548			168			1,351			496
	Investment in Sunoco Logistics:
	Revenues from external customers	4,502			—			12,215			—
	Intersegment revenues	26			—			136			—
		4,528			—			12,351			—
	Retail marketing:
	Revenues from external customers	5,297			—			15,805			—
	Intersegment revenues	1			—			6			—
		5,298			—			15,811			—
	All other:
	Revenues from external customers	85			76			279			254
	Intersegment revenues	10			28			67			65
		95			104			346			319
	Eliminations	(370		)	(211		)	(1,206		)	(555		)
	Total revenues	$	11,902		$	1,802		$	34,307		$	4,721
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013			2012
	Segment Adjusted EBITDA:
	Intrastate transportation and storage	$	108		$	121		$	352		$	470
	Interstate transportation and storage	310			324			968			701
	Midstream	125			134			322			335
	NGL transportation and services	100			50			257			155
	Investment in Sunoco Logistics	181			—			661			—
	Retail marketing	100			—			234			—
	All other	18			31			173			135
	Total	942			660			2,967			1,796
	Depreciation and amortization	(253		)	(162		)	(764		)	(419		)
	Interest expense, net of interest capitalized	(210		)	(147		)	(632		)	(479		)
	Gain on deconsolidation of Propane Business	—			—			—			1,057
	Gain on sale of AmeriGas common units	87			—			87			—
Gains (losses) on interest rate derivatives	—			—			46			(9		)
Non-cash unit-based compensation expense	(12		)	(10		)	(36		)	(31		)
Unrealized gains (losses) on commodity risk management activities	8			11			45			(60		)
LIFO valuation adjustments	6			—			22			—
Loss on extinguishment of debt	—			—			—			(115		)
Adjusted EBITDA attributable to discontinued operations	(12		)	(32		)	(75		)	(66		)
Adjusted EBITDA related to unconsolidated affiliates	(151		)	(106		)	(474		)	(302		)
Equity in earnings of unconsolidated affiliates	28			8			137			64
Other, net	5			11			13			23
Income from continuing operations before income tax expense	$	438		$	233		$	1,336		$	1,459
	September 30, 2013			December 31, 2012
Total assets:
Intrastate transportation and storage	$	4,613		$	4,691
Interstate transportation and storage	11,589			11,794
Midstream	3,339			5,098
NGL transportation and services	4,218			3,765
Investment in Sunoco Logistics	11,308			10,291
Retail marketing	3,734			3,926
All other	4,755			3,665
Total	$	43,556		$	43,230

Cash_And_Cash_Equivalents_Tabl

Cash And Cash Equivalents (Tables)	9 Months Ended
	Sep. 30, 2013
Cash and Cash Equivalents [Abstract]	'
Net Cash Provided By Operating Activities	'
	The net change in operating assets and liabilities included in cash flows from operating activities is comprised as follows:
		Nine Months Ended
		September 30,
		2013			2012
	Accounts receivable	$	(392	)	$	(67	)
	Accounts receivable from related companies	(50		)	(44		)
	Inventories	(132		)	(56		)
	Exchanges receivable	—			22
	Other current assets	(186		)	67
	Other non-current assets, net	(29		)	(32		)
	Accounts payable	398			43
	Accounts payable to related companies	(67		)	99
	Exchanges payable	36			(24		)
	Accrued and other current liabilities	92			(154		)
	Other non-current liabilities	(15		)	(3		)
	Price risk management assets and liabilities, net	(116		)	16
	Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(461	)	$	(133	)
Non-Cash Investing And Financing Activities	'
	Non-cash investing and financing activities are as follows:
		Nine Months Ended
		September 30,
		2013			2012
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	190		$	391
	AmeriGas limited partner interests received in exchange for contribution of Propane Business	$	—		$	1,123
	Regency common and Class F units received in exchange for contribution of SUGS	$	961		$	—
	NON-CASH FINANCING ACTIVITIES:
	Contributions receivable related to noncontrolling interest	$	—		$	13
	Issuance of common units in connection with acquisitions	$	—		$	112
	Issuance of common units in connection with the Holdco Acquisition	$	2,464		$	—

Inventories_Tables

Inventories (Tables)	9 Months Ended
	Sep. 30, 2013
Inventory, Gross [Abstract]	'
Schedule Of Inventories	'
	Inventories consisted of the following:
		September 30, 2013		December 31, 2012
	Natural gas and NGLs	$	509	$	334
	Crude oil	464		418
	Refined products	517		572
	Appliances, parts and fittings and other	167		171
	Total inventories	$	1,657	$	1,495

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2013
Fair Value Measurements [Abstract]	'
Fair Value Of Assets And Liabilities Measured And Recorded On Recurring Basis	'
	The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2013 and December 31, 2012 based on inputs used to derive their fair values:
					Fair Value Measurements at September 30, 2013
		Fair Value Total			Level 1			Level 2
	Assets:
	Interest rate derivatives	$	43		$	—		$	43
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	4			4			—
	Swing Swaps IFERC	1			—			1
	Fixed Swaps/Futures	84			84			—
	Options — Calls	1			—			1
	Forward Physical Swaps	1			—			1
	Power — Forwards	2			—			2
	Natural Gas Liquids — Forwards/Swaps	9			9			—
	Refined Products — Futures	25			25			—
	Total commodity derivatives	127			122			5
	Total Assets	$	170		$	122		$	48
	Liabilities:
	Interest rate derivatives	$	(111	)	$	—		$	(111	)
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(8		)	(8		)	—
	Swing Swaps IFERC	(2		)	—			(2		)
	Fixed Swaps/Futures	(58		)	(58		)	—
	Options — Calls	(1		)	—			(1		)
	Power:
	Forwards	(1		)	—			(1		)
	Options — Calls	(2		)	—			(2		)
	Natural Gas Liquids — Forwards/Swaps	(8		)	(8		)	—
	Refined Products — Futures	(16		)	(16		)	—
	Crude — Futures	(2		)	(2		)	—
	Total commodity derivatives	(98		)	(92		)	(6		)
	Total Liabilities	$	(209	)	$	(92	)	$	(117	)
					Fair Value Measurements at December 31, 2012
		Fair Value Total			Level 1			Level 2
	Assets:
	Interest rate derivatives	$	55		$	—		$	55
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	11			11			—
	Swing Swaps IFERC	3			—			3
	Fixed Swaps/Futures	96			94			2
	Options — Puts	1			—			1
	Options — Calls	3			—			3
	Forward Physical Swaps	1			—			1
	Power:
	Forwards	27			—			27
	Futures	1			1			—
	Options — Calls	2			—			2
	Natural Gas Liquids — Swaps	1			1			—
	Refined Products — Futures	5			1			4
	Total commodity derivatives	151			108			43
	Total Assets	$	206		$	108		$	98
	Liabilities:
	Interest rate derivatives	$	(223	)	$	—		$	(223	)
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(18		)	(18		)	—
	Swing Swaps IFERC	(2		)	—			(2		)
	Fixed Swaps/Futures	(103		)	(94		)	(9		)
	Options — Puts	(1		)	—			(1		)
	Options — Calls	(3		)	—			(3		)
	Power:
Forwards	(27		)	—			(27		)
Futures	(2		)	(2		)	—
Natural Gas Liquids — Swaps	(3		)	(3		)	—
Refined Products — Futures	(8		)	(1		)	(7		)
Total commodity derivatives	(167		)	(118		)	(49		)
Total Liabilities	$	(390	)	$	(118	)	$	(272	)

Net_Income_Per_Limited_Partner1

Net Income Per Limited Partner Unit (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	'
	A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows:
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013			2012
	Income from continuing operations	$	391		$	206		$	1,197		$	1,423
	Less: Income from continuing operations attributable to noncontrolling interest	49			22			227			10
	Income from continuing operations, net of noncontrolling interest	342			184			970			1,413
	General Partner’s interest in income from continuing operations	146			119			428			344
	Limited Partners’ interest in income from continuing operations	196			65			542			1,069
	Additional earnings allocated from (to) General Partner	—			1			(1		)	1
	Distributions on employee unit awards, net of allocation to General Partner	(3		)	(2		)	(8		)	(9		)
	Income from continuing operations available to Limited Partners	$	193		$	64		$	533		$	1,061
	Weighted average Limited Partner units – basic	374.1			245.1			342.8			233.8
	Basic income from continuing operations per Limited Partner unit	$	0.51		$	0.26		$	1.55		$	4.54
	Dilutive effect of unvested Unit Awards	1.4			1.2			1.3			1.2
	Weighted average Limited Partner units, assuming dilutive effect of unvested Unit Awards	375.5			246.3			344.1			235
	Diluted income from continuing operations per Limited Partner unit	$	0.51		$	0.26		$	1.55		$	4.52
	Basic income (loss) from discontinued operations per Limited Partner unit	$	0.04		$	(0.59	)	$	0.08		$	(0.63	)
	Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.04		$	(0.59	)	$	0.08		$	(0.63	)

Equity_Tables

Equity (Tables)	9 Months Ended
	Sep. 30, 2013
Schedule of Net IDR Subsidies [Table Text Block]	'
	As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:
			Quarters Ending
			31-Mar				30-Jun		30-Sep		31-Dec		Total Year
	2013		N/A				N/A		$	21	$	21	$	42
	2014		$	27.25			$	27.25	27.25		27.25		109
	2015		13.25				13.25		13.25		13.25		53
	2016		5.5				5.5		5.5		5.5		22
Change In Common Units	'
	The change in Common Units during the nine months ended September 30, 2013 was as follows:
		Number of Units
	Outstanding at December 31, 2012	301.5
	Common Units issued in connection with public offerings	13.8
	Common Units issued in connection with Equity Distribution Agreements	11.6
	Common Units issued in connection with the Distribution Reinvestment Plan	1.6
	Common Units issued in connection with the Holdco Acquisition	49.5
	Outstanding at September 30, 2013	378
Accumulated Other Comprehensive Income	'
	The following table presents the components of accumulated other comprehensive income (loss), net of tax:
		September 30, 2013				December 31, 2012
	Available-for-sale securities	$	1			$	—
	Foreign currency translation adjustment	(1		)		—
	Actuarial loss related to pensions and other postretirement benefits	(1		)		(10		)
	Equity investments, net	4				(9		)
	Subtotal	3				(19		)
	Amounts attributable to noncontrolling interest	—				6
	Total accumulated other comprehensive income (loss), net of tax	$	3			$	(13	)
ETP [Member]	'
Quarterly Distributions of Available Cash	'
	Following are distributions declared and/or paid by ETP subsequent to December 31, 2012:
	Quarter Ended		Record Date		Payment Date		Rate
	December 31, 2012		February 7, 2013		February 14, 2013		$	0.89375
	March 31, 2013		May 6, 2013		May 15, 2013		0.89375
	June 30, 2013		August 5, 2013		14-Aug-13		0.89375
	September 30, 2013		November 4, 2013		14-Nov-13		0.905
Investment in Sunoco Logistics:	'
Quarterly Distributions of Available Cash	'
	Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:
	Quarter Ended		Record Date		Payment Date		Rate
	December 31, 2012		February 8, 2013		February 14, 2013		$	0.545
	March 31, 2013		May 9, 2013		May 15, 2013		0.5725
	June 30, 2013		8-Aug-13		14-Aug-13		0.6
	September 30, 2013		8-Nov-13		14-Nov-13		0.63

Income_Tax_Tables

Income Tax (Tables)	9 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
	The follow table summarizes the Partnership’s income tax expense from continuing operations:
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013			2012
	Income tax expense from continuing operations	$	47		$	27		$	139		$	36
	Effective tax rate	11		%	12		%	10		%	2		%

Retirement_Benefits_Tables

Retirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2013
Retirement Benefits [Abstract]	'
Schedule of Net Benefit Costs [Table Text Block]	'
	The following tables set forth the components of net period benefit cost of the Partnership’s pension and other postretirement benefit plans:
		Three Months Ended September 30,
		2013						2012(1)
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
	Net Periodic Benefit Cost:
	Service cost	$	—		$	(1	)	$	1		$	—
	Interest cost	10			2			2			1
	Expected return on plan assets	(15		)	(3		)	(3		)	(2		)
	Prior service cost amortization	—			1			—			—
	Actuarial loss amortization	1			—			—			—
		(4		)	(1		)	—			(1		)
	Regulatory adjustment(2)	1			—			3			1
	Net periodic benefit cost	$	(3	)	$	(1	)	$	3		$	—
		Nine Months Ended September 30,
		2013						2012(1)
		Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
	Net Periodic Benefit Cost:
	Service cost	$	5		$	—		$	2		$	—
	Interest cost	28			5			5			1
	Expected return on plan assets	(45		)	(7		)	(6		)	(3		)
	Prior service cost amortization	—			1			—			—
	Actuarial loss amortization	2			—			—			—
	Settlement credits	(2		)	—			—			—
	Curtailment recognition(3)	—			—			—			(15		)
		(12		)	(1		)	1			(17		)
	Regulatory adjustment(2)	5			—			6			1
	Net periodic benefit cost	$	(7	)	$	(1	)	$	7		$	(16	)
	(1)	The three and nine months ended September 30, 2012 include components of net periodic benefit cost of Southern Union subsequent to the Southern Union Merger on March 26, 2012.
	(2)	Southern Union has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its MGE and NEG divisions.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.
	(3)	Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million.  Such gain was offset by establishment of a non-current refund liability in the amount of $60 million.  As such, the net curtailment gain recognition was $15 million.

Regulatory_Matters_Commitments1

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)	9 Months Ended
	Sep. 30, 2013
Environmental Remediation Obligations [Abstract]	'
Environmental Exit Costs by Cost [Table Text Block]	'
	The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
		September 30, 2013		December 31, 2012
	Current	$	38	$	46
	Non-current	185		165
	Total environmental liabilities	$	223	$	211
	During the three and nine months ended September 30, 2013, Sunoco recorded $8 million and $23 million, respectively, of expenditures related to environmental cleanup programs.

Price_Risk_Management_Assets_A1

Price Risk Management Assets And Liabilities (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative [Line Items]	'
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
		Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)		Amount of Gain/(Loss) Reclassified from AOCI into Income
				(Effective Portion)
				Three Months Ended September 30,								Nine Months Ended
												September 30,
				2013				2012				2013				2012
	Derivatives in cash flow hedging relationships:
	Commodity derivatives	Cost of products sold		$	3			$	9			$	5			$	21
	Total			$	3			$	9			$	5			$	21
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 September 30,								Nine Months Ended
												September 30,
				2013				2012				2013				2012
	Derivatives in fair value hedging relationships (including hedged item):
	Commodity derivatives	Cost of products sold		$	—			$	4			$	4			$	29
	Total			$	—			$	4			$	4			$	29
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 September 30,								Nine Months Ended
												September 30,
				2013				2012				2013				2012
	Derivatives not designated as hedging instruments:
	Commodity derivatives – Trading	Cost of products sold		$	(11	)		$	4			$	(12	)		$	(7	)
	Commodity derivatives – Non-Trading	Cost of products sold		(23		)		(5		)		(20		)		(13		)
	Commodity derivatives – Non-Trading	Deferred gas purchases		—				—				(3		)		—
	Interest rate derivatives	Gains (losses) on interest rate derivatives		—				—				46				(9		)
	Total			$	(34	)		$	(1	)		$	11			$	(29	)
Outstanding Commodity-Related Derivatives	'
	The following table details our outstanding commodity-related derivatives:
		September 30, 2013					December 31, 2012
		Notional Volume			Maturity		Notional Volume			Maturity
	Mark-to-Market Derivatives
	(Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	6,560,000			2013-2019		—			—
	Basis Swaps IFERC/NYMEX(1)	(27,402,500	)		2013-2017		(30,980,000	)		2013-2014
	Swing Swaps	1,690,000			2013-2016		—			—
	Power (Megawatt):
	Forwards	562,250			2013		19,650			2013
	Futures	97,212			2013		(1,509,300	)		2013
	Options — Calls	(1,700	)		2013		1,656,400			2013
	Crude (Bbls) — Futures	80,000			2013		—			—
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(5,300,000	)		2013-2014		150,000			2013
	Swing Swaps IFERC	6,965,000			2013-2016		(83,292,500	)		2013
	Fixed Swaps/Futures	(14,072,500	)		2013-2015		27,077,500			2013
	Forward Physical Contracts	(11,663,485	)		2013-2014		11,689,855			2013-2014
	Natural Gas Liquid (Bbls) — Forwards/Swaps	(1,182,000	)		2013-2014		(30,000	)		2013
	Refined Products (Bbls) — Futures	(93,327	)		2013-2014		(666,000	)		2013
	Fair Value Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(6,577,500	)		2013		(18,655,000	)		2013
	Fixed Swaps/Futures	(47,215,000	)		2014		(44,272,500	)		2013
	Hedged Item — Inventory	47,215,000			2014		44,272,500			2013
	Cash Flow Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(1,150,000	)		2013		—			—
	Fixed Swaps/Futures	(5,720,000	)		2013		(8,212,500	)		2013
	Natural Gas Liquid (Bbls) — Forwards/Swaps	(720,000	)		2013		(930,000	)		2013
	Refined Products (Bbls) — Futures	—			—		(98,000	)		2013
	Crude (Bbls) — Futures	(120,000	)		2013		—			—
	(1)	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Swaps Outstanding	'
	The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
	Entity		Term		Type(1)		Notional Amount Outstanding
							September 30, 2013				December 31, 2012
	ETP		July 2013(2)		Forward-starting to pay a fixed rate of 4.03% and receive a floating rate		$	—			$	400
	ETP		July 2014(2)		Forward-starting to pay a fixed rate of 4.25% and receive a floating rate		400				400
	ETP		Jul-18		Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		600				600
	ETP		Jun-21		Pay a floating rate plus a spread of 2.15% and receive a fixed rate of 4.65%		200				—
	ETP		Feb-23		Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%		400				—
	Southern Union		Nov-16		Pay a fixed rate of 2.97% and receive a floating rate		25				75
	Southern Union		Nov-21		Pay a fixed rate of 3.75% and receive a floating rate		450				450
	(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.
Fair Value Of Derivative Instruments	'
	The following table provides a summary of our derivative assets and liabilities:
		Fair Value of Derivative Instruments
		Asset Derivatives								Liability Derivatives
		September 30, 2013				December 31, 2012				September 30, 2013				December 31, 2012
	Derivatives designated as hedging instruments:
	Commodity derivatives (margin deposits)	$	16			$	8			$	(3	)		$	(10	)
		16				8				(3		)		(10		)
	Derivatives not designated as hedging instruments:
	Commodity derivatives (margin deposits)	112				110				(95		)		(116		)
	Commodity derivatives	32				33				(33		)		(34		)
	Current assets held for sale	—				1				—				—
	Non-current assets held for sale	—				1				—				—
	Current liabilities held for sale	—				—				—				(9		)
	Interest rate derivatives	43				55				(111		)		(223		)
		187				200				(239		)		(382		)
	Total derivatives	$	203			$	208			$	(242	)		$	(392	)
	In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.
Derivatives, Offsetting Fair Value Amounts [Table Text Block]	'
	The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
					Asset Derivatives								Liability Derivatives
			Balance Sheet Location		September 30, 2013				December 31, 2012				September 30, 2013				December 31, 2012
	Derivatives in offsetting agreements:
	OTC contracts		Price risk management assets (liabilities)		$	37			$	28			$	(38	)		$	(27	)
	Broker cleared derivative contracts		Other current assets (liabilities)		170				150				(159		)		(228		)
					207				178				(197		)		(255		)
	Offsetting agreements:
	Collateral paid to OTC counterparties		Other current assets		—				—				—				2
	Counterparty netting		Price risk management assets (liabilities)		(32		)		(25		)		32				25
	Payments on margin deposit		Other current assets		(15		)		—				34				59
					(47		)		(25		)		66				86
	Net derivatives with offsetting agreements				160				153				(131		)		(169		)
	Derivatives without offsetting agreements				43				55				(111		)		(223		)
	Total derivatives				$	203			$	208			$	(242	)		$	(392	)
Partnership's Derivative Assets And Liabilities	'
	The following tables summarize the amounts recognized with respect to our derivative financial instruments:
			Change in Value Recognized in OCI on Derivatives
			(Effective Portion)
			Three Months Ended September 30,								Nine Months Ended
											September 30,
			2013				2012				2013				2012
	Derivatives in cash flow hedging relationships:
	Commodity derivatives		$	(4	)		$	(7	)		$	4			$	14
	Total		$	(4	)		$	(7	)		$	4			$	14

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions For Period Presented [Table Text Block]	'
	The following table summarizes the affiliate revenue on our consolidated statements of operations:
		Three Months Ended September 30,				Nine Months Ended
						September 30,
		2013		2012		2013		2012
	Affiliated revenue	$	439	$	20	$	1,154	$	37
Related Party Balances For Period Presented [Table Text Block]	'
	The following table summarizes the related company balances on our consolidated balance sheets:
		September 30, 2013		December 31, 2012
	Accounts receivable from related companies:
	ETE	$	29	$	16
	Regency	75		10
	PES	20		60
	FGT	19		2
	Other	34		6
	Total accounts receivable from related companies:	$	177	$	94
	Accounts payable to related companies:
	ETE	$	8	$	7
	Regency	35		2
	PES	4		13
	FGT	3		—
	Other	3		2
	Total accounts payable to related companies:	$	53	$	24

Other_Information_Tables

Other Information (Tables)	9 Months Ended
	Sep. 30, 2013
Other Information [Abstract]	'
Other Current Assets	'
	Other current assets consisted of the following:
		September 30, 2013		December 31, 2012
	Deposits paid to vendors	$	55	$	41
	Prepaid expenses and other	263		293
	Total other current assets	$	318	$	334
Accrued And Other Current Liabilities	'
	Accrued and other current liabilities consisted of the following:
		September 30, 2013		December 31, 2012
	Interest payable	$	232	$	256
	Customer advances and deposits	55		44
	Accrued capital expenditures	187		356
	Accrued wages and benefits	181		236
	Taxes payable other than income taxes	276		203
	Income taxes payable	82		40
	Deferred income taxes	243		130
	Deferred revenue	2		—
	Other	359		297
	Total accrued and other current liabilities	$	1,617	$	1,562

Reportable_Segments_Tables

Reportable Segments (Tables)	9 Months Ended
	Sep. 30, 2013
Reportable Segments [Abstract]	'
Financial Information By Segments	'
	The following tables present the financial information by segment:
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013			2012
	Revenues:
	Intrastate transportation and storage:
	Revenues from external customers	$	502		$	503		$	1,711		$	1,402
	Intersegment revenues	51			53			155			130
		553			556			1,866			1,532
	Interstate transportation and storage:
	Revenues from external customers	296			309			973			761
	Intersegment revenues	15			12			19			14
		311			321			992			775
	Midstream:
	Revenues from external customers	683			757			2,021			1,845
	Intersegment revenues	256			107			775			309
		939			864			2,796			2,154
	NGL transportation and services:
	Revenues from external customers	537			157			1,303			459
	Intersegment revenues	11			11			48			37
		548			168			1,351			496
	Investment in Sunoco Logistics:
	Revenues from external customers	4,502			—			12,215			—
	Intersegment revenues	26			—			136			—
		4,528			—			12,351			—
	Retail marketing:
	Revenues from external customers	5,297			—			15,805			—
	Intersegment revenues	1			—			6			—
		5,298			—			15,811			—
	All other:
	Revenues from external customers	85			76			279			254
	Intersegment revenues	10			28			67			65
		95			104			346			319
	Eliminations	(370		)	(211		)	(1,206		)	(555		)
	Total revenues	$	11,902		$	1,802		$	34,307		$	4,721
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013			2012
	Segment Adjusted EBITDA:
	Intrastate transportation and storage	$	108		$	121		$	352		$	470
	Interstate transportation and storage	310			324			968			701
	Midstream	125			134			322			335
	NGL transportation and services	100			50			257			155
	Investment in Sunoco Logistics	181			—			661			—
	Retail marketing	100			—			234			—
	All other	18			31			173			135
	Total	942			660			2,967			1,796
	Depreciation and amortization	(253		)	(162		)	(764		)	(419		)
	Interest expense, net of interest capitalized	(210		)	(147		)	(632		)	(479		)
	Gain on deconsolidation of Propane Business	—			—			—			1,057
	Gain on sale of AmeriGas common units	87			—			87			—
	Gains (losses) on interest rate derivatives	—			—			46			(9		)
	Non-cash unit-based compensation expense	(12		)	(10		)	(36		)	(31		)
	Unrealized gains (losses) on commodity risk management activities	8			11			45			(60		)
	LIFO valuation adjustments	6			—			22			—
	Loss on extinguishment of debt	—			—			—			(115		)
	Adjusted EBITDA attributable to discontinued operations	(12		)	(32		)	(75		)	(66		)
	Adjusted EBITDA related to unconsolidated affiliates	(151		)	(106		)	(474		)	(302		)
	Equity in earnings of unconsolidated affiliates	28			8			137			64
	Other, net	5			11			13			23
	Income from continuing operations before income tax expense	$	438		$	233		$	1,336		$	1,459
		September 30, 2013			December 31, 2012
	Total assets:
Intrastate transportation and storage	$	4,613		$	4,691
Interstate transportation and storage	11,589			11,794
Midstream	3,339			5,098
NGL transportation and services	4,218			3,765
Investment in Sunoco Logistics	11,308			10,291
Retail marketing	3,734			3,926
All other	4,755			3,665
Total	$	43,556		$	43,230

Operations_And_Organization_Op

Operations And Organization Operations And Organization (Details)	4 Months Ended	9 Months Ended
	Apr. 30, 2013	Sep. 30, 2013
Lone Star L.L.C. [Member]	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	'	70.00%
FEP [Member]	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	'	50.00%
Citrus [Member]	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	'	50.00%
Fayetteville Express Pipeline, LLC [Member] | FEP [Member]	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	'	100.00%
ETE | Holdco [Member]	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	60.00%	60.00%
ETP [Member] | Holdco [Member]	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	40.00%	'

Acquisitions_Divestitures_and_1

Acquisitions, Divestitures and Related Transactions Narrative (Details) (USD $)	1 Months Ended					9 Months Ended
Share data in Millions, unless otherwise specified	Apr. 30, 2013	Oct. 05, 2012	Apr. 30, 2013	Apr. 30, 2013	Apr. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
	SUGS Contribution [Member]	Sunoco Merger [Member]	Holdco Acquisition [Member]	Southern Union [Member]	ETP [Member]	Missouri Gas Energy [Member]	New England Gas Company [Member]
				SUGS Contribution [Member]	SUGS Contribution [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'	'
Proceeds from Divestiture of Businesses	'	'	'	'	'	$975,000,000	'
Anticipated Proceeds From Planned Divestiture Of Business	'	'	'	'	'	'	40,000,000
Anticipated Other Noncurrent Liabilities from a Discontinued Operation	'	'	'	'	'	'	20,000,000
Business Acquisition, Purchase Price Allocation, Current Assets, Cash and Cash Equivalents	'	'	'	463,000,000	30,000,000	'	'
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares (instant)	'	'	49.5	'	'	'	'
Estimated Closing Adjustments	'	'	68,000,000	'	'	'	'
Business Acquisition Units Acquired	'	55	'	'	'	'	'
Business Acquisition, Cost of Acquired Entity, Cash Paid	'	'	1,400,000,000	'	'	'	'
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	31.4	'	'	'	'	'	'
Regency Class F Units Issued in SUGS Contribution	6.3	'	'	'	'	'	'
Business Combination, Consideration Transferred	'	$2,600,000,000	'	'	'	'	'

Cash_And_Cash_Equivalents_Net_

Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Cash and Cash Equivalents [Abstract]	'	'
Accounts receivable	($392)	($67)
Accounts receivable from related companies	-50	-44
Inventories	-132	-56
Exchanges receivable	0	22
Other current assets	-186	67
Other non-current assets, net	-29	-32
Accounts payable	398	43
Accounts payable to related companies	-67	99
Exchanges payable	36	-24
Accrued and other current liabilities	92	-154
Other non-current liabilities	-15	-3
Price risk management assets and liabilities, net	-116	16
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	($461)	($133)

Cash_And_Cash_Equivalents_NonC

Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
NON-CASH INVESTING ACTIVITIES:	'	'
Accrued capital expenditures	$190	$391
NON-CASH FINANCING ACTIVITIES:	'	'
Contributions receivable related to noncontrolling interest	0	13
Issuance of common units in connection with acquisitions	0	112
AmeriGas [Member]	'	'
NON-CASH INVESTING ACTIVITIES:	'	'
AmeriGas limited partner interests received in exchange for contribution of Propane Business	0	1,123
Regency [Member]	'	'
NON-CASH INVESTING ACTIVITIES:	'	'
AmeriGas limited partner interests received in exchange for contribution of Propane Business	961	0
Holdco Acquisition [Member]	'	'
NON-CASH FINANCING ACTIVITIES:	'	'
Issuance of common units in connection with acquisitions	$2,464	$0

Inventories_Inventory_Schedule

Inventories Inventory Schedule (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Inventory, Gross [Abstract]	'	'
Natural gas and NGLs	$509	$334
Crude oil	464	418
Refined products	517	572
Appliances, parts and fittings and other	167	171
Total inventories	$1,657	$1,495

Fair_Value_Measurements_Narrat

Fair Value Measurements Narrative (Details) (USD $)	9 Months Ended
In Billions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Fair Value Measurements [Abstract]	'	'
Transfers between levels in fair value hierarchy	$0	'
Aggregate fair value of long-term debt	17.16	17.84
Aggregate carrying amount of long-term debt	$16.65	$16.22

Fair_Value_Measurements_Fair_V

Fair Value Measurements Fair Value of Assets and Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Interest rate derivatives, Assets	$43	$55
Total commodity derivatives, Assets	127	151
Total Assets	170	206
Interest rate derivatives, Liabilities	-111	-223
Total commodity derivatives, Liabilities	-98	-167
Total Liabilities	-209	-390
Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Interest rate derivatives, Assets	0	0
Total commodity derivatives, Assets	122	108
Total Assets	122	108
Interest rate derivatives, Liabilities	0	0
Total commodity derivatives, Liabilities	-92	-118
Total Liabilities	-92	-118
Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Interest rate derivatives, Assets	43	55
Total commodity derivatives, Assets	5	43
Total Assets	48	98
Interest rate derivatives, Liabilities	-111	-223
Total commodity derivatives, Liabilities	-6	-49
Total Liabilities	-117	-272
Crude Oil [Member] | Future [Member]	'	'
Total commodity derivatives, Liabilities	-2	'
Crude Oil [Member] | Future [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Liabilities	-2	'
Crude Oil [Member] | Future [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Liabilities	0	'
Commodity Natural Gas [Member] | Future [Member]	'	'
Total commodity derivatives, Assets	84	'
Total commodity derivatives, Liabilities	-58	'
Commodity Natural Gas [Member] | Future [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	84	'
Total commodity derivatives, Liabilities	-58	'
Commodity Natural Gas [Member] | Future [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	0	'
Total commodity derivatives, Liabilities	0	'
Commodity Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member]	'	'
Total commodity derivatives, Assets	4	11
Total commodity derivatives, Liabilities	-8	-18
Commodity Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	4	11
Total commodity derivatives, Liabilities	-8	-18
Commodity Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	0	0
Total commodity derivatives, Liabilities	0	0
Commodity Natural Gas [Member] | Swing Swaps IFERC [Member]	'	'
Total commodity derivatives, Assets	1	3
Total commodity derivatives, Liabilities	-2	-2
Commodity Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	0	0
Total commodity derivatives, Liabilities	0	0
Commodity Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	1	3
Total commodity derivatives, Liabilities	-2	-2
Commodity Natural Gas [Member] | Fixed Swaps/Futures [Member]	'	'
Total commodity derivatives, Assets	'	96
Total commodity derivatives, Liabilities	'	-103
Commodity Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	'	94
Total commodity derivatives, Liabilities	'	-94
Commodity Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	'	2
Total commodity derivatives, Liabilities	'	-9
Commodity Natural Gas [Member] | Options - Puts [Member]	'	'
Total commodity derivatives, Assets	'	1
Total commodity derivatives, Liabilities	'	-1
Commodity Natural Gas [Member] | Options - Puts [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	'	0
Total commodity derivatives, Liabilities	'	0
Commodity Natural Gas [Member] | Options - Puts [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	'	1
Total commodity derivatives, Liabilities	'	-1
Commodity Natural Gas [Member] | Options - Calls [Member]	'	'
Total commodity derivatives, Assets	1	3
Total commodity derivatives, Liabilities	-1	-3
Commodity Natural Gas [Member] | Options - Calls [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	0	0
Total commodity derivatives, Liabilities	0	0
Commodity Natural Gas [Member] | Options - Calls [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	1	3
Total commodity derivatives, Liabilities	-1	-3
Commodity Natural Gas [Member] | Forward Physical Swaps [Member]	'	'
Total commodity derivatives, Assets	1	1
Commodity Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	0	0
Commodity Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	1	1
Commodity Derivatives - Power [Member] | Forward Swaps [Member]	'	'
Total commodity derivatives, Assets	2	27
Total commodity derivatives, Liabilities	-1	-27
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	0	0
Total commodity derivatives, Liabilities	0	0
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	2	27
Total commodity derivatives, Liabilities	-1	-27
Commodity Derivatives - Power [Member] | Future [Member]	'	'
Total commodity derivatives, Liabilities	'	-2
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Liabilities	'	-2
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Liabilities	'	0
Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member]	'	'
Total commodity derivatives, Assets	'	1
Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	'	1
Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	'	0
Commodity Derivatives - Power [Member] | Options - Calls [Member]	'	'
Total commodity derivatives, Assets	'	2
Total commodity derivatives, Liabilities	-2	'
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	'	0
Total commodity derivatives, Liabilities	0	'
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	'	2
Total commodity derivatives, Liabilities	-2	'
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member]	'	'
Total commodity derivatives, Assets	9	'
Total commodity derivatives, Liabilities	-8	-3
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	9	'
Total commodity derivatives, Liabilities	-8	-3
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	0	'
Total commodity derivatives, Liabilities	0	0
Commodity Derivatives - NGLs [Member] | Natural Gas Liquids - Forwards/Swaps [Member]	'	'
Total commodity derivatives, Assets	'	1
Commodity Derivatives - NGLs [Member] | Natural Gas Liquids - Forwards/Swaps [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	'	1
Commodity Derivatives - NGLs [Member] | Natural Gas Liquids - Forwards/Swaps [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	'	0
Commodity Derivatives - Refined Products [Member] | Future [Member]	'	'
Total commodity derivatives, Assets	25	5
Total commodity derivatives, Liabilities	-16	-8
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value Measurements, Quoted Prices In Active Markets For Identical Assets And Liabilities (Level 1) [Member]	'	'
Total commodity derivatives, Assets	25	1
Total commodity derivatives, Liabilities	-16	-1
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value Measurements, Significant Observable Inputs (Level 2) [Member]	'	'
Total commodity derivatives, Assets	0	4
Total commodity derivatives, Liabilities	$0	($7)

Net_Income_Per_Limited_Partner2

Net Income Per Limited Partner Unit Reconciliation of Net Income and Weighted Avg Units Used in Computing Basic and Diluted EPU (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Earnings Per Share [Abstract]	'	'	'	'
Income from continuing operations	$391	$206	$1,197	$1,423
Less: Income from continuing operations attributable to noncontrolling interest	49	22	227	10
Income from continuing operations, net of noncontrolling interest	342	184	970	1,413
General Partner’s interest in income from continuing operations	146	119	428	344
Limited Partners’ interest in income from continuing operations	196	65	542	1,069
Additional earnings allocated from (to) General Partner	0	1	-1	1
Distributions on employee unit awards, net of allocation to General Partner	-3	-2	-8	-9
Income from continuing operations available to Limited Partners	$193	$64	$533	$1,061
Weighted average Limited Partner units – basic	374.1	245.1	342.8	233.8
Basic income from continuing operations per Limited Partner unit	0.51	0.26	1.55	4.54
Dilutive effect of unvested Unit Awards	1.4	1.2	1.3	1.2
Weighted average Limited Partner units, assuming dilutive effect of unvested Unit Awards	375.5	246.3	344.1	235
Diluted income from continuing operations per Limited Partner unit	0.51	0.26	1.55	4.52
Basic income (loss) from discontinued operations per Limited Partner unit	0.04	-0.59	0.08	-0.63
Diluted income (loss) from discontinued operations per Limited Partner unit	0.04	-0.59	0.08	-0.63

Debt_Obligations_Narrative_Det

Debt Obligations Narrative (Details) (USD $)

1 Months Ended

9 Months Ended

1 Months Ended

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Jun. 24, 2013

Jan. 31, 2013

Jan. 31, 2013

Jan. 31, 2013

Jan. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Jun. 24, 2013

Jun. 24, 2013

Jun. 24, 2013

Sep. 30, 2013

Jan. 31, 2013

Jan. 31, 2013

Sep. 30, 2013

3.6% Senior Notes due February 1, 2023 [Member]

5.15% Senior Notes due February 1, 2043 [Member]

3.45% Senior Notes due January 2023 [Member]

4.95% Senior Notes due January 2043 [Member]

4.15% Senior Notes due October 1, 2020 [Member]

4.9% Senior Notes due February 1, 2024 [Member]

5.95% Senior Notes due October 1, 2043 [Member]

Sunoco Logistics Revolving Credit Facility, due August 2016 [Member]

Sunoco Logistics Revolving Credit Facility, due August 2014 [Member] [Member]

Sunoco Logistics Revolving Credit Facility, due August 2013 [Member]

Sunoco Logistics Revolving Credit Facility, due April 2015 [Member]

7.60% Senior Notes, due February 1, 2024 [Member]

8.25% Senior Notes, due November 14, 2029 [Member]

Junior Subordinated Debt [Member]

ETP [Member]

ETP [Member]

Investment in Sunoco Logistics:

ETP Revolving Credit Facility, due October 27, 2016 [Member]

Senior notes, aggregate principal amount

'

'

'

'

$800,000,000

$450,000,000

$350,000,000

$350,000,000

$700,000,000

$350,000,000

$450,000,000

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

3.60%

5.15%

3.45%

4.95%

4.15%

4.90%

5.95%

'

'

'

'

7.60%

8.25%

'

'

'

'

'

Senior notes, net proceeds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,470,000,000

1,240,000,000

691,000,000

'

Repayments of Long-term Debt

455,000,000

6,312,000,000

4,744,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

ETP Note Exchange

'

'

'

1,090,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent of SUG Notes Exchanged for ETP Notes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

77.00%

89.00%

91.00%

'

'

'

'

Line of Credit Facility, Current Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35,000,000

'

'

'

'

'

'

2,500,000,000

ETP Revolving Credit Facility

0

0

'

'

'

'

'

'

'

'

'

'

'

0

35,000,000

'

'

'

'

'

'

'

Debt, Current

240,000,000

240,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

$350,000,000

$200,000,000

'

'

'

'

'

'

'

'

'

Equity_Narrative_Details

Equity Narrative (Details) (USD $)

9 Months Ended

9 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

In Millions, except Per Share data, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Aug. 07, 2013

Sep. 30, 2013

Goldman Sachs [Member]

Citrus Merger [Member]

Holdco Transaction [Member]

ETP [Member]

April 2013 [Member]

Equity Distribution Agreement entered in January 2013 [Member]

Equity Distribution Agreement entered in May 2013 [Member]

equity distribution agreement [Member]

April 2013 [Member]

Distribution Reinvestment Plan [Member]

Class H Units [Member]

Class H Units [Member]

quarters

quarters

Distribution Reinvestment Plan [Member]

Partners' Capital Account, Units, Redeemed

'

'

'

'

'

'

'

'

'

'

'

'

50.2

'

Class H Incremental Cash Distributions

'

'

'

'

'

'

'

'

'

'

'

'

'

$329

Relinquishment of Rights of Incentive Distributions

'

'

'

220

210

'

'

'

'

'

'

'

'

'

Equity Distribution Agreement Commissions

6

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount

426

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Issuance of Common Limited Partners Units

1,301

772

13

'

'

'

'

'

'

568

657

76

'

'

Common units - outstanding, value

'

'

'

'

'

'

'

$200

$800

'

'

'

'

'

Partners' Capital Account, Units, Sold in Public Offering

13.8

'

'

'

'

'

13.8

'

'

'

'

'

'

'

Price per Unit

$48.05

'

'

'

'

'

'

'

'

'

'

'

'

'

Common units - issued in connection with the DRIP

'

'

'

'

'

'

'

'

'

11.6

'

1.6

'

'

Equity Distribution Reinvestment Program, Capacity, Shares

'

'

'

'

'

2.7

'

'

'

'

'

'

'

'

Number of periods of incentive distributions to be relinquished in future periods contingent upon closing of proposed transaction.

'

'

'

16

12

'

'

'

'

'

'

'

'

'

Allocation of Profits, Losses and Other by Sunoco, Percent

'

'

'

'

'

'

'

'

'

'

'

'

50.05%

'

Distributions by Sunoco, IDRs and General Partner Interest

'

'

'

'

'

'

'

'

'

'

'

'

50.05%

'

Equity_Common_Unit_Activity_De

Equity Common Unit Activity (Details)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Partners' Capital Notes [Abstract]	'
Outstanding at December 31, 2012	301.5
Common Units issued in connection with public offerings	13.8
Common Units issued in connection with the Holdco Acquisition	49.5
Outstanding at September 30, 2013	378
equity distribution agreement [Member]	'
Partners' Capital Notes [Abstract]	'
Common Units issued in connection with Equity Distribution Agreements	11.6
Distribution Reinvestment Plan [Member]	'
Partners' Capital Notes [Abstract]	'
Common Units issued in connection with Equity Distribution Agreements	1.6

Equity_Quarterly_Distributions

Equity (Quarterly Distributions Of Available Cash) (Details) (USD $)	3 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012
Distribution Made to Member or Limited Partner [Line Items]	'	'	'	'
Record Date	4-Nov-13	5-Aug-13	6-May-13	7-Feb-13
Payment Date	14-Nov-13	14-Aug-13	15-May-13	14-Feb-13
Rate	$0.91	$0.89	$0.89	$0.89
Investment in Sunoco Logistics:	'	'	'	'
Distribution Made to Member or Limited Partner [Line Items]	'	'	'	'
Record Date	8-Nov-13	8-Aug-13	9-May-13	8-Feb-13
Payment Date	14-Nov-13	14-Aug-13	15-May-13	14-Feb-13
Rate	$0.63	$0.60	$0.57	$0.55

Equity_Accumulated_Other_Compr

Equity (Accumulated Other Comprehensive Income, Net Of Tax) (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Partners' Capital Notes [Abstract]	'	'
Accumulated Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	$1	$0
Foreign currency translation adjustment	-1	0
Actuarial loss related to pensions and other postretirement benefits	-1	-10
Equity investments, net	4	-9
Subtotal	3	-19
Amounts attributable to noncontrolling interest	0	6
Total accumulated other comprehensive income (loss), net of tax	$3	($13)

Equity_Net_IDR_Schedule_Detail

Equity Net IDR Schedule (Details) (USD $)	Sep. 30, 2013
In Millions, unless otherwise specified
2013 [Member]	'
IDR Subsidies	$42
2014 [Member]	'
IDR Subsidies	109
2015 [Member]	'
IDR Subsidies	53
2016 [Member]	'
IDR Subsidies	22
March 31 [Member] | 2014 [Member]	'
IDR Subsidies	27.25
March 31 [Member] | 2015 [Member]	'
IDR Subsidies	13.25
March 31 [Member] | 2016 [Member]	'
IDR Subsidies	5.5
June 30 [Member] | 2014 [Member]	'
IDR Subsidies	27.25
June 30 [Member] | 2015 [Member]	'
IDR Subsidies	13.25
June 30 [Member] | 2016 [Member]	'
IDR Subsidies	5.5
September 30 [Member] | 2013 [Member]	'
IDR Subsidies	21
September 30 [Member] | 2014 [Member]	'
IDR Subsidies	27.25
September 30 [Member] | 2015 [Member]	'
IDR Subsidies	13.25
September 30 [Member] | 2016 [Member]	'
IDR Subsidies	5.5
December 31 [Member] | 2013 [Member]	'
IDR Subsidies	21
December 31 [Member] | 2014 [Member]	'
IDR Subsidies	27.25
December 31 [Member] | 2015 [Member]	'
IDR Subsidies	13.25
December 31 [Member] | 2016 [Member]	'
IDR Subsidies	$5.50

UnitBased_Compensation_Plans_D

Unit-Based Compensation Plans (Details) (USD $)	9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013
Weighted average grant-date fair value of awards per unit	$45.74
Total awards remain unvested	2,840,725
Compensation expense of remaining unvested awards	$72
Weighted average period related to unvested awards in years	'1 year 9 months 0 days
Employee [Member]	'
Total unvested awards granted to employees	1,142,663
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'5 years 0 months 0 days
Director [Member]	'
Total granted unvested awards to directors	9,060
Sunoco Logistics Unit-Based Compensation Plan [Member]	'
Total awards remain unvested	918,031
Compensation expense of remaining unvested awards	$16
Weighted average period related to unvested awards in years	'2 years 5 months 0 days
Minimum [Member] | Director [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'3 years 0 months 0 days
Maximum [Member] | Director [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'5 years 0 months 0 days

Income_Tax_Income_Tax_Expense_

Income Tax Income Tax Expense Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Tax Expense table [Abstract]	'	'	'	'
Income Tax Expense (Benefit)	$47	$27	$139	$36
Effective Income Tax Rate, Continuing Operations	11.00%	12.00%	10.00%	2.00%

Retirement_Benefits_Details

Retirement Benefits (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Dec. 31, 2012	Sep. 30, 2012
Net Periodic Benefit Cost:	'		'		'		'	'
Pretax curtailment gain	'		'		'		$75	'
Noncurrent refund liability	'		'		'		60	'
Curtailment recognition(2)	'		'		0		'	-15
Pension Benefits	'		'		'		'	'
Net Periodic Benefit Cost:	'		'		'		'	'
Service cost	0		1	[1]	5		'	2	[1]
Interest cost	10		2	[1]	28		'	5	[1]
Expected return on plan assets	-15		-3	[1]	-45		'	-6	[1]
Prior service cost amortization	0		0		0		'	0
Actuarial loss amortization	1		0	[1]	2		'	0	[1]
Settlement credits	'		'		-2		'	0	[1]
Curtailment recognition(2)	'		'		0	[2]	'	0	[1],[2]
Net periodic benefit cost subtotal	-4		0	[1]	-12		'	1	[1]
Regulatory adjustment(2)	1	[3]	3	[1],[3]	5	[3]	'	6	[1],[3]
Net periodic benefit cost	-3		3	[1]	-7		'	7	[1]
Other Postretirement Benefits	'		'		'		'	'
Net Periodic Benefit Cost:	'		'		'		'	'
Service cost	-1		0	[1]	0		'	0	[1]
Interest cost	2		1	[1]	5		'	1	[1]
Expected return on plan assets	-3		-2	[1]	-7		'	-3	[1]
Prior service cost amortization	1		0		1		'	0
Actuarial loss amortization	0		0	[1]	0		'	0	[1]
Settlement credits	'		'		0		'	0	[1]
Curtailment recognition(2)	'		'		0	[2]	-15	-15	[1],[2]
Net periodic benefit cost subtotal	-1		-1	[1]	-1		'	-17	[1]
Regulatory adjustment(2)	0	[3]	1	[1],[3]	0	[3]	'	1	[1],[3]
Net periodic benefit cost	($1)		$0	[1]	($1)		'	($16)	[1]
[1]	(1) The three and nine months ended September 30, 2012 include components of net periodic benefit cost of Southern Union subsequent to the Southern Union Merger on March 26, 2012.
[2]	(2) Southern Union has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its MGE and NEG divisions. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.(3) Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million. Such gain was offset by establishment of a non-current refund liability in the amount of $60 million. As such, the net curtailment gain recognition was $15 million.
[3]	.

Regulatory_Matters_Commitments2

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details) (USD $)	3 Months Ended		9 Months Ended			0 Months Ended		9 Months Ended		3 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Jan. 12, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
						AmeriGas [Member]	Regency 4.50% Senior Notes Due 2023 [Member]	State and Local Jurisdiction [Member]	U.S Federal [Member]	Attorney General of Commonwealth [Member]
Contingent Residual Support Agreement, Amount	'	'	'	'	'	$1,550,000,000	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	'	'	'	'	'	4.50%	'	'	'
Guarantor Obligations, Current Carrying Value	'	'	'	'	'	'	600,000,000	'	'	'
Maximum lease expiration year	'	'	31-Dec-56	'	'	'	'	'	'	'
Rental expense under operating lease	31,000,000	12,000,000	93,000,000	29,000,000	'	'	'	'	'	'
Operating Leases, Rent Expense, Contingent Rentals	8,000,000	'	18,000,000	'	'	'	'	'	'	'
Operating Leases, Income Statement, Sublease Revenue	6,000,000	'	16,000,000	'	'	'	'	'	'	'
Maximum Amount of Attorney's Fees	'	'	'	'	'	'	'	950,000	250,000	'
Loss contingency accrual, at carrying value	38,000,000	'	38,000,000	'	42,000,000	'	'	'	'	'
Legal Fees	'	'	'	'	'	'	'	'	'	19,000,000
Percentage Of Recovery	'	'	'	'	'	'	'	'	'	50.00%
Reimbursement expert and consultant cost, maximum	'	'	'	'	'	'	'	'	'	150,000
Sites where remediation operations are responsibility of third parties	'	'	39	'	'	'	'	'	'	'
Payments for Environmental Liabilities	$8,000,000	'	$23,000,000	'	'	'	'	'	'	'

Regulatory_Matters_Commitments3

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Environmental Exit Cost [Line Items]	'	'
Current	$38	$46
Non-current	185	165
Total environmental liabilities	$223	$211

Price_Risk_Management_Assets_A2

Price Risk Management Assets And Liabilities Narrative (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
	ETP [Member]	Price Risk Management Liabilities [Member]
Derivative [Line Items]	'	'
Settlement of Interest Rate Swaps	$400	'
Option Premiums	'	-7
Price Risk Cash Flow Hedge Unrealized Gain (Loss) to be Reclassified During Next 12 Months	$1	'

Price_Risk_Management_Assets_A3

Price Risk Management Assets And Liabilities Outstanding Commodity-Related Derivatives (Details)	Sep. 30, 2013	Dec. 31, 2012
	MMbtu	MMbtu
Trading [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	6,560,000	0
Term of commodity derivatives - Minimum	'2013	'
Term of commodity derivatives - Maximum	'2019	'
Trading [Member] | Power [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	97,212	-1,509,300
Term of commodity derivatives - Maximum	'2013	'2013
Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	-27,402,500	-30,980,000
Term of commodity derivatives - Minimum	'2013	'2013
Term of commodity derivatives - Maximum	'2017	'2014
Trading [Member] | Options - Calls [Member] | Power [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	-1,700	1,656,400
Term of commodity derivatives - Maximum	'2013	'2013
Trading [Member] | Forwards Swaps [Member] | Power [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	562,250	19,650
Term of commodity derivatives - Maximum	'2013	'2013
Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	1,690,000	'
Term of commodity derivatives - Minimum	'2013	'
Term of commodity derivatives - Maximum	'2016	'
Non Trading [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member]	'	'
Term of commodity derivatives - Minimum	'2013	'
Term of commodity derivatives - Maximum	'2015	'
Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	-5,300,000	150,000
Term of commodity derivatives - Minimum	'2013	'
Term of commodity derivatives - Maximum	'2014	'2013
Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Fair Value Hedging Derivatives [Member]	'	'
Notional Volume	-6,577,500	-18,655,000
Term of commodity derivatives - Maximum	'2013	'2013
Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Cash Flow Hedging Derivatives [Member]	'	'
Notional Volume	-1,150,000	0
Term of commodity derivatives - Maximum	'2013	'
Non Trading [Member] | Hedged Item - Inventory [Member] | Natural Gas [Member] | Fair Value Hedging Derivatives [Member]	'	'
Notional Volume	47,215,000	44,272,500
Term of commodity derivatives - Maximum	'2014	'2013
Non Trading [Member] | Forwards Swaps [Member] | NGL [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	-1,182,000	-30,000
Term of commodity derivatives - Minimum	'2013	'
Term of commodity derivatives - Maximum	'2014	'2013
Non Trading [Member] | Forwards Swaps [Member] | NGL [Member] | Cash Flow Hedging Derivatives [Member]	'	'
Notional Volume	-720,000	-930,000
Term of commodity derivatives - Maximum	'2013	'2013
Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	6,965,000	-83,292,500
Term of commodity derivatives - Minimum	'2013	'
Term of commodity derivatives - Maximum	'2016	'2013
Non Trading [Member] | Forward Physical Swaps [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	-11,663,485	11,689,855
Term of commodity derivatives - Minimum	'2013	'2013
Term of commodity derivatives - Maximum	'2014	'2014
Non Trading [Member] | Future [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	-14,072,500	27,077,500
Term of commodity derivatives - Maximum	'	'2013
Non Trading [Member] | Future [Member] | Natural Gas [Member] | Fair Value Hedging Derivatives [Member]	'	'
Notional Volume	-47,215,000	-44,272,500
Term of commodity derivatives - Maximum	'2014	'2013
Non Trading [Member] | Future [Member] | Natural Gas [Member] | Cash Flow Hedging Derivatives [Member]	'	'
Notional Volume	-5,720,000	-8,212,500
Term of commodity derivatives - Maximum	'2013	'2013
Non Trading [Member] | Future [Member] | Refined Products [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	-93,327	-666,000
Term of commodity derivatives - Maximum	'	'2013
Non Trading [Member] | Future [Member] | Refined Products [Member] | Cash Flow Hedging Derivatives [Member]	'	'
Notional Volume	'	-98,000
Term of commodity derivatives - Maximum	'	'2013
ETP [Member] | Trading [Member] | Crude Oil [Member] | Mark-To-Market Derivatives [Member]	'	'
Notional Volume	80,000	'
Term of commodity derivatives - Maximum	'2013	'
ETP [Member] | Non Trading [Member] | Future [Member] | Crude Oil [Member] | Cash Flow Hedging Derivatives [Member]	'	'
Notional Volume	-120,000	'
Term of commodity derivatives - Maximum	'2013	'

Price_Risk_Management_Assets_A4

Price Risk Management Assets And Liabilities Interest Rate Swaps Outstanding (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Fixed Interest Rate Of 4.02% [Member] | Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member]	'		'
Term	'July 2013	[1]	'
Fixed rate	4.03%		'
Fixed Interest Rate Of 4.26 Percent [Member] | Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member]	'		'
Term	'July 2014	[1]	'
Fixed rate	4.25%		'
Floating Interest Rate Of 6.70% [Member] | Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member]	'		'
Term	'July 2018		'
Fixed rate	6.70%		'
Floating Interest Rate of 4.65 Percent [Member] | Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member]	'		'
Term	'June 2021		'
Fixed rate	4.65%		'
Floating Interest Rate Of 3.60 Percent [Member] | Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member]	'		'
Term	'February 2023		'
Fixed rate	3.60%		'
Fixed Rate of 2.91 Percent [Member] | Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member]	'		'
Term	'November 2016		'
Spread on floating rate	2.97%		'
Fixed Rate of 3.75 Percent [Member] | Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member]	'		'
Term	'November 2021		'
Spread on floating rate	3.75%		'
July 2013 [Member] | Interest Rate Derivatives [Member] | ETP [Member]	'		'
Notional Amount	$0		$400
Type	'Forward-starting to pay a fixed rate of 4.03% and receive a floating rate		'
July 2014 [Member] | Interest Rate Derivatives [Member] | ETP [Member]	'		'
Notional Amount	400		400
Type	'Forward-starting to pay a fixed rate of 4.25% and receive a floating rate		'
July 2018 [Member] | Interest Rate Derivatives [Member] | ETP [Member]	'		'
Notional Amount	600		600
Type	'Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		'
June 2021 [Member] | Interest Rate Derivatives [Member] | ETP [Member]	'		'
Notional Amount	200		0
Type	'Pay a floating rate plus a spread of 2.15% and receive a fixed rate of 4.65%		'
February 2023 [Member] | Interest Rate Derivatives [Member] | ETP [Member]	'		'
Notional Amount	400		0
Type	'Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%		'
November 2016 [Member] | Interest Rate Derivatives [Member] | Southern Union [Member]	'		'
Notional Amount	25		75
Type	'Pay a fixed rate of 2.97% and receive a floating rate		'
November 2021 [Member] | Interest Rate Derivatives [Member] | Southern Union [Member]	'		'
Notional Amount	$450		$450
Type	'Pay a fixed rate of 3.75% and receive a floating rate		'
[1]	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.

Price_Risk_Management_Assets_A5

Price Risk Management Assets And Liabilities Fair Value of Derivative Instruments (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	$16	$8
Total derivatives liabilities	-3	-10
Not Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	203	208
Total derivatives liabilities	242	392
Embedded Derivatives in Regency Preferred Units [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	187	200
Total derivatives liabilities	-239	-382
Commodity [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	32	33
Total derivatives liabilities	-33	-34
Commodity Derivatives (Margin Deposits) [Member] | Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	16	8
Total derivatives liabilities	-3	-10
Commodity Derivatives (Margin Deposits) [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	112	110
Total derivatives liabilities	-95	-116
Interest Rate Derivatives [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	43	55
Total derivatives liabilities	111	223
Current Assets Held For Sale [Member] | Commodity [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	0	1
Total derivatives liabilities	0	0
Non-Current Assets Held For Sale [Member] | Commodity [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	0	1
Total derivatives liabilities	0	0
Current Liabilities Held For Sale [Member] | Commodity [Member] | Not Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	0	0
Total derivatives liabilities	$0	($9)

Price_Risk_Management_Assets_A6

Price Risk Management Assets And Liabilities Partnership's Derivative Assets And Liabilities, Recognized OCI On Derivatives (Effective Portion) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Change in Value Recognized in OCI on Derivatives (Effective Portion)	($4)	($7)	$4	$14
Derivatives In Cash Flow Hedging Relationships - Commodity Derivatives [Member]	'	'	'	'
Change in Value Recognized in OCI on Derivatives (Effective Portion)	($4)	($7)	$4	$14

Price_Risk_Management_Assets_A7

Price Risk Management Assets And Liabilities Partnership's Derivative Assets And Liabilities, Amount Of Gain/(Loss) Reclassified From AOCI Into Income (Effective Portion) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$3	$9	$5	$21
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	0	4	4	29
Amount of Gain (Loss) Recognized In Income On Derivatives	-34	-1	11	-29
Increase (Decrease) in Fair Value of Derivative Instruments, Not Designated as Hedging Instruments	0	0	46	-9
Commodity Derivatives - Trading [Member]	'	'	'	'
Amount of Gain (Loss) Recognized In Income On Derivatives	-11	4	-12	-7
Commodity Derivatives [Member]	'	'	'	'
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	3	9	5	21
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	0	4	4	29
Amount of Gain (Loss) Recognized In Income On Derivatives	-23	-5	-20	-13
Commodity [Member] | Deferred Gas Purchases [Member]	'	'	'	'
Amount of Gain (Loss) Recognized In Income On Derivatives	$0	$0	($3)	$0

Price_Risk_Management_Assets_A8

Price Risk Management Assets And Liabilities Fair Value of Derivatives, Netting Basis (Details) (USD $)

3 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Netting [Member]

Netting [Member]

Bi-lateral contracts [Member]

Bi-lateral contracts [Member]

Broker cleared derivative contracts [Member]

Broker cleared derivative contracts [Member]

Asset Fair Value, Netting Offset [Member]

Asset Fair Value, Netting Offset [Member]

Liability Fair Value, Netting Offset [Member]

Liability Fair Value, Netting Offset [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Netting [Member]

Netting [Member]

Netting [Member]

Netting [Member]

Netting [Member]

Netting [Member]

Netting [Member]

Netting [Member]

Interest Rate Derivatives [Member]

Interest Rate Derivatives [Member]

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Instruments, Gain (Loss) Recognized in Income, Net

($34)

($1)

$11

($29)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Asset, Fair Value, Gross Asset

'

'

'

'

207

178

37

28

170

150

'

'

'

'

203

208

43

55

Derivative Liability, Fair Value, Gross Liability

'

'

'

'

-197

-255

-38

-27

-159

-228

'

'

'

'

-242

-392

-111

-223

Collateral Paid To OTC Counterparties

'

'

'

'

'

'

'

'

'

'

0

0

0

2

'

'

'

'

Derivative Asset, Fair Value, Gross Liability

'

'

'

'

-32

-25

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Liability, Fair Value, Gross Asset

'

'

'

'

32

25

'

'

'

'

'

'

'

'

'

'

'

'

Payments on Margin Deposits

'

'

'

'

'

'

'

'

'

'

-15

0

34

59

'

'

'

'

Derivative Asset, Fair Value, Net

'

'

'

'

160

153

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Liability, Fair Value, Net

'

'

'

'

-131

-169

'

'

'

'

'

'

'

'

'

'

'

'

Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value

'

'

'

'

'

'

'

'

'

'

43

55

'

'

'

'

'

'

Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value

'

'

'

'

'

'

'

'

'

'

'

'

($111)

($223)

'

'

'

'

Related_Party_Transactions_Aff

Related Party Transactions Affiliated Revenue (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Related Party Transactions [Abstract]	'	'	'	'
Affiliated revenue	$439	$20	$1,154	$37

Related_Party_Transactions_Rel

Related Party Transactions Related Party A/R and A/P (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Accounts Receivable, Related Parties, Current	$177	$94
Accounts Payable, Related Parties, Current	53	24
ETE	'	'
Accounts Receivable, Related Parties, Current	29	16
Accounts Payable, Related Parties, Current	8	7
Regency	'	'
Accounts Receivable, Related Parties, Current	75	10
Accounts Payable, Related Parties, Current	35	2
PES	'	'
Accounts Receivable, Related Parties, Current	20	60
Accounts Payable, Related Parties, Current	4	13
FGT	'	'
Accounts Receivable, Related Parties, Current	19	2
Accounts Payable, Related Parties, Current	3	0
Other	'	'
Accounts Receivable, Related Parties, Current	34	6
Accounts Payable, Related Parties, Current	$3	$2

Other_Information_Other_Curren

Other Information Other Current Assets (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Other Information [Abstract]	'	'
Deposits paid to vendors	$55	$41
Prepaid expenses and other	263	293
Total other current assets	$318	$334

Other_Information_Accrued_and_

Other Information Accrued and Other Current Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Other Information [Abstract]	'	'
Interest payable	$232	$256
Customer advances and deposits	55	44
Accrued capital expenditures	187	356
Accrued wages and benefits	181	236
Taxes payable other than income taxes	276	203
Income taxes payable	82	40
Deferred income taxes	243	130
Deferred revenue	2	0
Other	359	297
Total accrued and other current liabilities	$1,617	$1,562

Reportable_Segments_Financial_

Reportable Segments Financial Information by Segment (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Total revenues	$11,902	$1,802	$34,307	$4,721	'
Adjusted EBITDA	942	660	2,967	1,796	'
Depreciation and amortization	-253	-162	-764	-419	'
Interest expense, net of interest capitalized	-210	-147	-632	-479	'
Gain on deconsolidation of Propane Business	0	0	0	1,057	'
Gain on sale of AmeriGas common units	87	0	87	0	'
Losses on interest rate derivatives	0	0	46	-9	'
Non-cash unit-based compensation expense	-12	-10	-36	-31	'
Unrealized gains (losses) on commodity risk management activities	8	11	45	-60	'
LIFO valuation adjustments	6	0	22	0	'
Loss on extinguishment of debt	0	0	0	-115	'
Adjusted EBITDA attributable to discontinued operations	-12	-32	-75	-66	'
Adjusted EBITDA related to unconsolidated affiliates	-151	-106	-474	-302	'
Equity in earnings of unconsolidated affiliates	28	8	137	64	'
Other, net	5	11	13	23	'
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	438	233	1,336	1,459	'
Total assets	43,556	'	43,556	'	43,230
Intrastate transportation and storage:	'	'	'	'	'
Revenue from external customers	502	503	1,711	1,402	'
Intersegment revenues	51	53	155	130	'
Segment revenues	553	556	1,866	1,532	'
Adjusted EBITDA	108	121	352	470	'
Total assets	4,613	'	4,613	'	4,691
Interstate transportation and storage:	'	'	'	'	'
Revenue from external customers	296	309	973	761	'
Intersegment revenues	15	12	19	14	'
Segment revenues	311	321	992	775	'
Adjusted EBITDA	310	324	968	701	'
Total assets	11,589	'	11,589	'	11,794
Midstream:	'	'	'	'	'
Revenue from external customers	683	757	2,021	1,845	'
Intersegment revenues	256	107	775	309	'
Segment revenues	939	864	2,796	2,154	'
Adjusted EBITDA	125	134	322	335	'
Total assets	3,339	'	3,339	'	5,098
NGL transportation and services:	'	'	'	'	'
Revenue from external customers	537	157	1,303	459	'
Intersegment revenues	11	11	48	37	'
Segment revenues	548	168	1,351	496	'
Adjusted EBITDA	100	50	257	155	'
Total assets	4,218	'	4,218	'	3,765
Investment in Sunoco Logistics:	'	'	'	'	'
Revenue from external customers	4,502	0	12,215	0	'
Intersegment revenues	26	0	136	0	'
Segment revenues	4,528	0	12,351	0	'
Adjusted EBITDA	181	0	661	0	'
Total assets	11,308	'	11,308	'	10,291
Retail marketing:	'	'	'	'	'
Revenue from external customers	5,297	0	15,805	0	'
Intersegment revenues	1	0	6	0	'
Segment revenues	5,298	0	15,811	0	'
Adjusted EBITDA	100	0	234	0	'
Total assets	3,734	'	3,734	'	3,926
All Other [Member]	'	'	'	'	'
Revenue from external customers	85	76	279	254	'
Intersegment revenues	10	28	67	65	'
Segment revenues	95	104	346	319	'
Adjusted EBITDA	18	31	173	135	'
Total assets	4,755	'	4,755	'	3,665
Intersegment Elimination [Member]	'	'	'	'	'
Segment revenues	($370)	($211)	($1,206)	($555)	'