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

DEI_Document

DEI Document	9 Months Ended
	Sep. 30, 2013	Nov. 01, 2013
Entity Information [Line Items]	'	'
Entity Registrant Name	'Energy Transfer Equity, L.P.	'
Entity Central Index Key	'0001276187	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Document Type	'10-Q	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Amendment Flag	'false	'
Entity Common Stock, Shares Outstanding	'	280,711,650

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
ASSETS	'	'
Cash and cash equivalents	$1,177	$372
Accounts receivable, net	3,546	3,057
Accounts receivable from related companies	51	71
Inventories	1,697	1,522
Exchanges receivable	43	55
Price risk management assets	36	25
Current assets held for sale	16	184
Other current assets	321	311
Total current assets	6,887	5,597
PROPERTY, PLANT AND EQUIPMENT	32,623	30,388
ACCUMULATED DEPRECIATION	-2,949	-2,104
PROPERTY, PLANT AND EQUIPMENT, net	29,674	28,284
NON-CURRENT ASSETS HELD FOR SALE	145	985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,087	4,737
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	20	43
GOODWILL	6,428	6,434
INTANGIBLE ASSETS, net	2,195	2,291
OTHER NON-CURRENT ASSETS, net	607	533
Total assets	50,043	48,904
LIABILITIES AND EQUITY	'	'
Accounts payable	3,544	3,107
Accounts payable to related companies	11	15
Exchanges payable	190	156
Price risk management liabilities	69	115
Accrued and other current liabilities	1,922	1,754
Current maturities of long-term debt	298	613
Current liabilities held for sale	13	85
Total current liabilities	6,047	5,845
NON-CURRENT LIABILTIES HELD FOR SALE	70	142
LONG-TERM DEBT, less current maturities	22,011	21,440
PREFERRED UNITS	0	331
DEFERRED INCOME TAXES	3,708	3,566
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	78	162
OTHER NON-CURRENT LIABILITIES	893	995
COMMITMENTS AND CONTINGENCIES (Note 14)	'	'
PREFERRED UNITS OF SUBSIDIARY	32	73
EQUITY:	'	'
General Partner	-2	0
Limited Partners:	'	'
Common Unitholders	1,401	2,125
Accumulated other comprehensive income (loss)	1	-12
Total partners’ capital	1,400	2,113
Noncontrolling interest	15,804	14,237
Total equity	17,204	16,350
Total liabilities and equity	$50,043	$48,904

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	$915	$734	$2,752	$1,791
NGL sales	968	585	2,468	1,705
Crude sales	4,215	0	11,408	0
Gathering, transportation and other fees	786	627	2,341	1,712
Refined product sales	4,633	0	13,945	0
Other	969	158	2,814	443
Total revenues	12,486	2,104	35,728	5,651
COSTS AND EXPENSES:	'	'	'	'
Cost of products sold	11,064	1,228	31,436	3,205
Operating expenses	403	208	1,127	614
Depreciation and amortization	332	211	962	571
Selling, general and administrative	158	98	499	353
Total costs and expenses	11,957	1,745	34,024	4,743
OPERATING INCOME	529	359	1,704	908
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense, net of interest capitalized	-298	-237	-913	-732
Bridge loan related fees	0	0	0	-62
Equity in earnings of unconsolidated affiliates	38	21	182	118
Gain on deconsolidation of Propane Business	0	0	0	1,057
Losses on extinguishment of debt	0	0	-7	-123
Gains (losses) on interest rate derivatives	3	-6	55	-23
Gain on sale of AmeriGas common units	87	0	87	0
Other, net	33	-3	0	28
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	392	134	1,108	1,171
Income tax expense from continuing operations	49	26	136	33
INCOME FROM CONTINUING OPERATIONS	343	108	972	1,138
Income (loss) from discontinued operations	13	-142	44	-136
NET INCOME (LOSS)	356	-34	1,016	1,002
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST	205	-69	648	747
NET INCOME ATTRIBUTABLE TO PARTNERS	151	35	368	255
GENERAL PARTNER’S INTEREST IN NET INCOME	1	0	1	1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$150	$35	$367	$254
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:	'	'	'	'
Basic	0.52	0.23	1.24	1.06
Diluted	0.52	0.23	1.24	1.06
NET INCOME PER LIMITED PARTNER UNIT:	'	'	'	'
Basic	0.54	0.13	1.31	0.97
Diluted	0.54	0.13	1.31	0.97

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 (loss)	$356	($34)	$1,016	$1,002
Other comprehensive income (loss), net of tax:	'	'	'	'
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	-3	-7	-5	-15
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 loss 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
Other comprehensive income (loss), net of tax	11	-6	21	-15
Comprehensive income (loss)	367	-40	1,037	987
Less: Comprehensive income (loss) attributable to noncontrolling interest	213	-67	660	739
Comprehensive income attributable to partners	$154	$27	$377	$248

Consolidated_Statement_Of_Equi

Consolidated Statement Of Equity (USD $)	Total	General Partner	Common Unitholders	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
In Millions, unless otherwise specified
Balance, December 31, 2012 at Dec. 31, 2012	$16,350	$0	$2,125	($12)	$14,237
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Distributions to partners	-544	-1	-543	0	0
Distributions to noncontrolling interest	-1,050	0	0	0	-1,050
Subsidiary units issued for cash	1,450	0	96	0	1,354
Noncontrolling Interest, Increase from Equity Issuance or Sale of Parent Equity Interest	0	-1	-506	0	507
Non-cash compensation expense, net of units tendered by employees for tax withholdings	48	0	4	0	44
Capital contributions from noncontrolling interest	15	0	0	0	15
Other, net	-2	-1	-1	4	-4
Conversion of Stock, Amount Converted	41	0	0	0	41
Deemed Distribution related to SUGS Transaction	-141	0	-141	0	0
Other comprehensive income, net of tax	21	0	0	9	12
Net income	1,016	1	367	0	648
Balance, September 30, 2013 at Sep. 30, 2013	$17,204	($2)	$1,401	$1	$15,804

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	$1,016	$1,002
Reconciliation of net income to net cash provided by operating activities:	'	'
Depreciation and amortization	962	571
Deferred income taxes	244	37
Gain on curtailment of other postretirement benefit plans	0	-15
Amortization of finance costs charged to interest	-43	6
Bridge loan related fees	0	62
Non-cash compensation expense	43	34
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
Losses on extinguishment of debt	7	123
LIFO valuation adjustments	-22	0
Equity in earnings of unconsolidated affiliates	-182	-118
Distributions from unconsolidated affiliates	269	153
Other non-cash	22	74
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation (see Note 2)	-382	-120
Net cash provided by operating activities	1,847	897
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Cash paid for Southern Union Merger, net of cash received	0	2,972
Cash paid for all other acquisitions, net of cash received	-5	-10
Cash proceeds from the sale of MGE assets (See Note 2)	973	0
Cash proceeds from the sale of AmeriGas common units	346	0
Capital expenditures (excluding allowance for equity funds used during construction)	-2,504	-2,239
Contributions in aid of construction costs	11	28
Contributions to unconsolidated affiliates	-3	-35
Distributions from unconsolidated affiliates in excess of cumulative earnings	326	139
Proceeds from the sale of assets	72	35
Cash proceeds from contribution of propane operations	0	1,443
Other	-49	-2
Net cash used in investing activities	-833	-3,613
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from borrowings	9,768	9,081
Repayments of long-term debt	-9,439	-6,144
Subsidiary equity offerings, net of issue costs	1,450	1,084
Distributions to partners	-544	-491
Debt issuance costs	-56	-99
Distributions to noncontrolling interest	-1,050	-688
Capital contributions received from noncontrolling interest	15	24
Redemption of Preferred Units	-340	0
Other, net	-13	-5
Net cash provided by (used in) financing activities	-209	2,762
INCREASE IN CASH AND CASH EQUIVALENTS	805	46
CASH AND CASH EQUIVALENTS, beginning of period	372	126
CASH AND CASH EQUIVALENTS, end of period	$1,177	$172

Operations_And_Organization

Operations And Organization	9 Months Ended
	Sep. 30, 2013
Operations And Organization [Abstract]	'
Operations And Organization	'
	OPERATIONS AND ORGANIZATION:
	Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
	The consolidated financial statements of ETE presented herein include the results of operations of:
	•	the Parent Company;
	•	our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”); and
	•	ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency.
	Business Operations
	The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 19 for stand-alone financial information apart from that of the consolidated partnership information included herein.
	Our activities are primarily conducted through our operating subsidiaries as follows:
	•	ETP’s operations are conducted through the following subsidiaries:
	•	ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through 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.
	•	Energy Transfer Interstate Holdings, LLC, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which 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.
	•	Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, New Mexico and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.
	Our reportable segments reflect the following reportable business segments:
	•	Investment in ETP, including the consolidated operations of ETP.
	•	Investment in Regency, including the consolidated operations of Regency.
	•	Corporate and Other, including the following:
	•	activities of the Parent Company; and
	•	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
	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 months 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 of the Partnership’s subsidiaries 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 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.
	As a result of the Southern Union Merger in March 2012 and the Holdco Transaction in October 2012, the periods presented herein do not include activities from Southern Union or Sunoco prior to the consummation of the respective mergers and/or transactions.

Acquisitions

Acquisitions	9 Months Ended
	Sep. 30, 2013
ACQUISITIONS AND DIVESTITURE [Abstract]	'
Acquisitions	'
	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”). As of January 2013, Laclede Gas Company, a subsidiary of The Laclede Group, Inc., 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 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.
	ETP’s 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. 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. 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.
	Regency’s Acquisition of PVR Partners, L.P.
	On October 10, 2013, Regency and PVR Partners, L.P. (“PVR”) announced the approval of a merger agreement, pursuant to which Regency intends to propose to acquire PVR. This acquisition will be a unit-for-unit transaction plus a one-time $40 million cash payment to PVR unitholders which represents total consideration of $5.6 billion, including the assumption of net debt of $1.8 billion. The holders of PVR common units, PVR Class B Units and PVR Special Units (“PVR Unit(s)”) will receive 1.02 Regency common units in exchange for each PVR Unit held on the applicable record date. The transaction is subject to the approval of PVR’s unitholders, Hart-Scott-Rodino Antitrust Improvements Act approval and other customary closing conditions. The transaction is expected to close in the first quarter of 2014.

Investments_in_Affiliates

Investments in Affiliates	9 Months Ended
	Sep. 30, 2013
INVESTMENTS IN UNCONSOLIDATED AFFILIATES [Abstract]	'
Investments in and Advances to Affiliates	'
	INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
	The following investments in unconsolidated affiliates are reflected in our consolidated financial statements using the equity method:
	•	AmeriGas. ETP received approximately 30 million AmeriGas common units in connection with the Partnership’s contribution of its retail propane operations to AmeriGas in January 2012. On July 12, 2013, ETP sold 7.5 million of its AmeriGas common units for net proceeds of $346 million. ETP currently owns approximately 22 million AmeriGas common units.
	•	Citrus. ETP owns a 50% interest in Citrus, which owns 100% of FGT, an approximate 5,400 mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc.
	•	FEP. ETP owns a 50% interest in the FEP, which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company, LLC in Panola County, Mississippi.
	•	HPC. Regency owns a 49.99% interest in HPC, which, through its ownership of the Regency Intrastate Gas System, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system.
	•	MEP. Regency owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama.
	•	PES. Sunoco owns an approximate 30% non-operating interest in PES, a joint venture with The Carlyle Group, L.P., which owns a refinery in Philadelphia. Sunoco has a ten-year supply contract for gasoline and diesel produced at the refinery for its retail marketing business.
	The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented).
		Three Months Ended September 30,				Nine Months Ended
						September 30,
		2013		2012		2013		2012
	Revenue	$	5,208	$	1,840	$	14,710	$	4,251
	Operating income	163		273		803		807
	Net income	21		111		409		376
	In addition to the equity method investments described above, ETP and Regency have other equity method investments, which are not significant to our consolidated financial statements.

Cash_And_Cash_Equivalents

Cash And Cash Equivalents	9 Months Ended
	Sep. 30, 2013
Supplemental Cash Flow Information [Abstract]	'
Cash And Cash Equivalents	'
	CASH AND CASH EQUIVALENTS:
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
	Non-cash investing and financing activities are as follows:
		Nine Months Ended
		September 30,
		2013			2012
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	260		$	432
	Net gains (losses) from subsidiary common unit transactions	$	(410	)	$	33
	AmeriGas limited partner interest received in Propane Contribution	$	—		$	1,123
	NON-CASH FINANCING ACTIVITIES:
	Issuance of common units in connection with Southern Union Merger	$	—		$	2,354
	Subsidiary issuances of common units in connection with certain acquisitions	$	—		$	112

Inventories_Notes

Inventories (Notes)	9 Months Ended
	Sep. 30, 2013
Inventory, Net [Abstract]	'
Inventories	'
	INVENTORIES:
	Inventories consisted of the following:
		September 30,		December 31,
		2013		2012
	Natural gas and NGLs	$	513	$	338
	Crude oil	464		418
	Refined products	517		572
	Other	203		194
	Total inventories	$	1,697	$	1,522
	ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventory and designates 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, interest rate derivatives, the Preferred Units and embedded derivatives in the Regency Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements, and we discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. At December 31, 2012, the fair value of the Preferred Units was based predominantly on an income approach model and considered Level 3. The Preferred Units were redeemed on April 1, 2013.
	Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of September 30, 2013 and December 31, 2012 was $22.96 billion and $24.15 billion, respectively. As of September 30, 2013 and December 31, 2012, the aggregate carrying amount of our consolidated debt obligations was $22.31 billion and $22.05 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
		30-Sep-13
		Fair Value			Level 1			Level 2			Level 3
		Total
	Assets:
	Interest rate derivatives	$	43		$	—		$	43		$	—
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	4			4			—			—
	Swing Swaps IFERC	1			—			1			—
	Fixed Swaps/Futures	90			84			6			—
	Options — Calls	1			—			1			—
	Forward Physical Contracts	1			—			1			—
	NGLs — Forwards/Swaps	10			9			1			—
	Power — Forwards	2			—			2			—
	Refined Products — Futures	25			25			—			—
	Total commodity derivatives	134			122			12			—
	Total Assets	$	177		$	122		$	55		$	—
	Liabilities:
	Interest rate derivatives	$	(112	)	$	—		$	(112	)	$	—
	Embedded derivatives in the Regency Preferred Units	(23		)	—			—			(23		)
	Commodity derivatives:
	Condensate — Forward Swaps	(2		)	—			(2		)	—
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(8		)	(8		)	—			—
	Swing Swaps IFERC	(2		)	—			(2		)	—
	Fixed Swaps/Futures	(59		)	(58		)	(1		)	—
	Options — Calls	(1		)	—			(1		)	—
	NGLs — Forwards/Swaps	(10		)	(8		)	(2		)	—
	Power:
	Forwards	(1		)	—			(1		)	—
	Options — Calls	(2		)	—			(2		)	—
	Refined Products — Futures	(16		)	(16		)	—			—
	Crude — Futures	(2		)	(2		)	—			—
	Total commodity derivatives	(103		)	(92		)	(11		)	—
	Total Liabilities	$	(238	)	$	(92	)	$	(123	)	$	(23	)
		Fair Value Measurements at
		31-Dec-12
		Fair Value			Level 1			Level 2			Level 3
		Total
	Assets:
	Interest rate derivatives	$	55		$	—		$	55		$	—
	Commodity derivatives:
	Condensate — Forward Swaps	2			—			2			—
	Natural Gas:
	Basis Swaps IFERC/NYMEX	11			11			—			—
	Swing Swaps IFERC	3			—			3			—
	Fixed Swaps/Futures	98			94			4			—
	Options — Calls	3			—			3			—
	Options — Puts	1			—			1			—
	Forward Physical Contracts	1			—			1			—
	NGLs — Swaps	2			1			1			—
	Power:
	Forwards	27			—			27			—
	Futures	1			1			—			—
	Options — Calls	2			—			2			—
	Refined Products — Futures	5			1			4			—
	Total commodity derivatives	156			108			48			—
	Total Assets	$	211		$	108		$	103		$	—
Liabilities:
Interest rate derivatives	$	(235	)	$	—		$	(235	)	$	—
Preferred Units	(331		)	—			—			(331		)
Embedded derivatives in the Regency Preferred Units	(25		)	—			—			(25		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)	(18		)	—			—
Swing Swaps IFERC	(2		)	—			(2		)	—
Fixed Swaps/Futures	(103		)	(94		)	(9		)	—
Options — Calls	(3		)	—			(3		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Swaps	(4		)	(3		)	(1		)	—
Power:
Forwards	(27		)	—			(27		)	—
Futures	(2		)	(2		)	—			—
Refined Products — Futures	(8		)	(1		)	(7		)	—
Total commodity derivatives	(168		)	(118		)	(50		)	—
Total Liabilities	$	(759	)	$	(118	)	$	(285	)	$	(356	)
The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the nine months ended September 30, 2013. There were no transfers between the fair value hierarchy levels during the nine months ended September 30, 2013 or 2012.
Balance, December 31, 2012	$	(356	)
Realized loss included in other income (expense)	(9		)
Net unrealized gain included in other income (expense)	2
Redemption of Preferred Units	340
Balance, September 30, 2013	$	(23	)

Net_Income_per_Limited_Partner

Net Income per Limited Partner Unit	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Net Income Per Limited Partner Unit	'
	NET INCOME PER LIMITED PARTNER UNIT:
	A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows:
		Three Months Ended September 30,					Nine Months Ended
							September 30,
		2013		2012			2013			2012
	Income from continuing operations	$	343	$	108		$	972		$	1,138
	Less: Income from continuing operations attributable to noncontrolling interest	195		45			623			860
	Income from continuing operations, net of noncontrolling interest	148		63			349			278
	Less: General Partner’s interest in income from continuing operations	1		—			1			—
	Income from continuing operations available to Limited Partners	$	147	$	63		$	348		$	278
	Basic Income from Continuing Operations per Limited Partner Unit:
	Weighted average limited partner units	280.7		280			280.4			262.3
	Basic income from continuing operations per Limited Partner unit	$	0.52	$	0.23		$	1.24		$	1.06
	Basic income (loss) from discontinued operations per Limited Partner unit	$	0.02	$	(0.10	)	$	0.07		$	(0.09	)
	Diluted Income from Continuing Operations per Limited Partner Unit:
	Income from continuing operations available to Limited Partners	$	147	$	63		$	348		$	278
	Dilutive effect of equity-based compensation of subsidiaries	—		—			(1		)	(1		)
	Diluted income from continuing operations available to Limited Partners	$	147	$	63		$	347		$	277
	Weighted average limited partner units	280.7		280			280.4			262.3
	Diluted income from continuing operations per Limited Partner unit	$	0.52	$	0.23		$	1.24		$	1.06
	Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.02	$	(0.10	)	$	0.07		$	(0.09	)

Debt_Obligations

Debt Obligations	9 Months Ended
	Sep. 30, 2013
Debt Obligations [Abstract]	'
Debt Obligations	'
	DEBT OBLIGATIONS:
	Parent Company Indebtedness
	The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets.
	Term Loan
	On March 23, 2012, ETE entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, as Administrative Agent, and the other lenders from time to time party thereto (the “Term Lenders”), which became effective on March 26, 2012. The Term Credit Agreement has a scheduled maturity date of March 26, 2017, with an option for ETE to extend the term subject to the terms and conditions set forth therein. Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2 billion. Interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of ETE for each interest period. The applicable margin for LIBOR rate loans is 3.00% and the applicable margin for base rate loans is 2.00%.  Proceeds of the borrowings under the Term Credit Agreement were used to partially fund the Southern Union Merger, to repay amounts outstanding under the Parent Company Credit Facility, and to pay transaction fees and expenses related to the Southern Union Merger, the new Term Credit Agreement and other transactions incidental thereto.
	During the nine months ended September 30, 2013, proceeds from ETP’s acquisition of ETE’s 60% interest in Holdco were used to repay borrowings of $1.10 billion on ETE’s Term Credit Agreement. The total amount outstanding as of September 30, 2013 was $900 million.
	Revolving Credit Facility
	As of September 30, 2013, there were no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million.
	Senior Notes
	The Parent Company currently has outstanding on aggregate of $1.80 billion in principal amount of 7.5% Senior Notes due 2020 (the “ETE Notes”).
	Refinancing Activities
	On October 30, 2013, the Parent Company commenced an offer to purchase for cash up to $400 million aggregate principal amount outstanding of the ETE Notes pursuant to the Offer to Purchase Statement dated October 30, 2013, which tender offer amount may be increased at the discretion of the Parent Company. The tender offer is subject to a financing condition, and the Parent Company may obtain financing for purchases of ETE Notes in the tender offer pursuant to the issuance of new senior notes, borrowings under a new term loan facility or other debt financings. In this regard, the Parent Company has also announced that it has launched a syndication of a new senior secured term loan credit facility to refinance its existing term loan facility under the Term Credit Agreement. The Parent Company is also arranging a new five-year revolving credit facility for up to $600 million.
	Subsidiary Indebtedness
	Regency Senior Notes
	In April 2013, in conjunction with Southern Union’s contribution of SUGS to Regency, Regency issued $600 million aggregate principal amount of senior notes in a private placement that mature November 2023 and bear interest at 4.5% payable semi-annually. At any time prior to August 2023, Regency may redeem some or all of the senior notes due 2023 at a price equal to 100% of the principal amount plus a make-whole premium and accrued interest. On or after August 1, 2023, Regency may redeem some or all of the senior notes due 2023 at a price equal to 100% plus accrued interest.
	In June 2013, Regency redeemed all of the $163 million outstanding 9.375% Senior Notes due 2016 for $178 million cash, including accrued and unpaid interest of $7 million and other fees and expenses.
	In September 2013, Regency issued $400 million aggregate principal amount of senior notes that mature September 2020 and bear interest at 5.75% payable semi-annually. Regency used the net proceeds of approximately $394 million from the offering to repay borrowings outstanding under the Regency Credit Facility.
	ETP 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 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.
	Sunoco Logistics Senior Notes
	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.
	ETP 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.
	Subsidiary 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 ETP’s current and future unsecured debt. There were no outstanding borrowings under the ETP Credit Facility as of September 30, 2013.
	Regency Credit Facility
	In May 2013, Regency entered into an amendment to the Regency Credit Facility to increase the borrowing capacity of the Regency Credit Facility to $1.2 billion with a $300 million uncommitted incremental facility and extended the maturity date to May 21, 2018. Indebtedness under the Regency Credit Facility is secured by all of Regency’s and certain of its subsidiaries’ tangible and intangible assets and guaranteed by certain of Regency’s subsidiaries.
	As of September 30, 2013, the Regency Credit Facility had a balance outstanding of $176 million in revolving credit loans and approximately $15 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2013, which was reduced by any letters of credit, was approximately $1.01 billion, and the weighted average interest rate on the total amount outstanding as of September 30, 2013 was 2.19%.
	Southern Union Credit Facilities
	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 and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2013.

Redeemable_Preferred_Units_Not

Redeemable Preferred Units (Notes)	9 Months Ended
	Sep. 30, 2013
Temporary Equity Disclosure [Abstract]	'
Redeemable Preferred Units [Text Block]	'
	PREFERRED UNITS:
	On April 1, 2013, ETE paid $300 million to redeem (the “Redemption”) all of its 3,000,000 outstanding Preferred Units from Regency GP Acquirer L.P. (“GE Regency”) pursuant to a Preferred Unit Redemption Agreement, dated as of March 28, 2013, between ETE and GE Regency. Prior to the Redemption, on March 28, 2013, ETE paid GE Regency $40 million in cash in exchange for GE Regency relinquishing its right to receive any premium in connection with a future redemption or conversion of the Preferred Units.

Equity

Equity

9 Months Ended

Sep. 30, 2013

Partners' Capital Notes [Abstract]

'

Equity

'

EQUITY:

ETE Common Unit Activity

The change in ETE Common Units during the nine months ended September 30, 2013 was as follows:

Number of

Units

Outstanding at December 31, 2012

280

Issuance of restricted units under equity incentive plans

0.8

Outstanding at September 30, 2013

280.8

Sales of Common Units by Subsidiaries

The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Regency and the underlying book value arising from the issuance or redemption of units by ETP or Regency (excluding transactions with the Parent Company) as capital transactions.

As a result of ETP’s and Regency’s issuances of common units during the nine months ended September 30, 2013, we recognized decreases in partners’ capital of $410 million.

Sales of Common Units by ETP

In January 2013 and May 2013, ETP entered into Equity Distribution Agreements pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. During the nine months ended September 30, 2013, ETP 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. ETP 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 ETP 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 ETP Common Units. As of September 30, 2013, a total of 2.7 million ETP Common Units remain available to be issued under the existing registration statement.

In April 2013, ETP issued 13.8 million ETP Common Units at $48.05 per ETP 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 “ETP Class H Units” below, ETP redeemed and cancelled 50.2 million of its common units in connection with the issuance of Class H Units to ETE.

ETP 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 ETP’s consolidated financial statements.

ETP Class H Units

Pursuant to an Exchange and Redemption Agreement previously entered into among 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.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2012:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2012

February 7, 2013

February 19, 2013

$

0.635

March 31, 2013

May 6, 2013

May 17, 2013

0.645

June 30, 2013

August 5, 2013

August 19, 2013

0.655

30-Sep-13

November 4, 2013

November 19, 2013

0.6725

ETP 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

31-Dec-12

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

August 14, 2013

0.89375

30-Sep-13

November 4, 2013

November 14, 2013

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 the 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 “ETP 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

Regency Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2012:

Quarter Ended

Record Date

Payment Date

Rate

31-Dec-12

February 7, 2013

February 14, 2013

$

0.46

31-Mar-13

May 6, 2013

May 13, 2013

0.46

30-Jun-13

August 5, 2013

August 14, 2013

0.465

30-Sep-13

November 4, 2013

November 14, 2013

0.47

In conjunction with Southern Union’s contribution of SUGS to Regency, ETE agreed to forego incentive distributions with respect to the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

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

31-Dec-12

February 8, 2013

February 14, 2013

$

0.545

31-Mar-13

May 9, 2013

May 15, 2013

0.5725

30-Jun-13

August 8, 2013

August 14, 2013

0.6

30-Sep-13

November 8, 2013

November 14, 2013

0.63

Accumulated Other Comprehensive Income (Loss)

The following table presents the components of accumulated other comprehensive income (loss), net of tax:

September 30,

December 31, 2012

2013

Net gains (losses) on commodity related hedges

$

—

$

(3

)

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

(22

)

Amounts attributable to noncontrolling interest

(2

)

10

Total accumulated other comprehensive income (loss), net of tax

$

1

$

(12

)

UnitBased_Compensation_Plans

Unit-Based Compensation Plans	9 Months Ended
	Sep. 30, 2013
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]	'
Unit-Based Compensation Plans	'
	UNIT-BASED COMPENSATION PLANS:
	We and certain of our subsidiaries have equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase common units, restricted units, phantom units, DERs, common unit appreciation rights, and other unit-based awards.
	ETE Long-Term Incentive Plan
	During the nine months ended September 30, 2013, an equity award relating to 750,000 ETE Common Units was granted to an ETE employee and equity awards relating to 6,042 ETE Common Units were granted to ETE directors. The weighted average grant-date fair value of these awards was $55.95 per unit. As of September 30, 2013, a total of 804,190 unit awards remain subject to vesting or other conditions. We expect to recognize a total of $39 million in compensation expense over a weighted average period of 4.3 years related to unvested awards.
	ETP Unit-Based Compensation Plans
	During the nine months ended September 30, 2013, ETP 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 ETP expects to recognize $72 million in compensation expense over a weighted average period of 1.8 years related to unvested awards.
	Regency Unit-Based Compensation Plans
	During the nine months ended September 30, 2013, Regency employees and directors were granted 52,360 Regency phantom units with five-year service vesting requirements. As of September 30, 2013, a total of 1,168,247 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $23.41 per unit. Regency expects to recognize a total of $20 million in compensation expense over a weighted average period of 3.5 years related to Regency’s unvested phantom units.
	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_Taxes_Notes

Income Taxes (Notes)	9 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]	'
Income Tax Disclosure [Text Block]	'
	INCOME TAXES:
	The following 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	$	49		$	26		$	136		$	33
	Effective tax rate	13		%	19		%	12		%	3		%
	The decrease in the effective tax rate for the three months ended September 30, 2013 compared to the same period last year was primarily due to Southern Union’s non-deductible executive compensation as a result of the Southern Union Merger in 2012. 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, subsequent to the mergers and related transactions that occurred in 2012. The Southern Union Merger was completed in the first quarter of 2012 and the Holdco Transaction and Sunoco Merger were completed in the fourth quarter 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

Retirement Benefits	9 Months Ended
	Sep. 30, 2013
BENEFITS [Abstract]	'
Postemployment Benefits Disclosure [Text Block]	'
		RETIREMENT BENEFITS:
	The following table sets 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 ETP’s 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 $33 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 $98 million and $31 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.
	Certain of our subsidiaries’ joint venture agreements require that they fund their proportionate shares of capital contributions to their unconsolidated affiliates.  Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
	Litigation and Contingencies
	We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business.  Natural gas and crude 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.
	Litigation Relating to the PVR Merger
	Four putative class action lawsuits challenging the merger have been filed, two in the Court of Chancery of the State of Delaware: (i) David Naiditch v. PVR Partners, L.P., et al. (Case No. 9015-VCL); and (ii) Robert P. Frutkin v. Edward B. Cloues II, et al. (Case No. 9020-VCL), and two in the Court of Common Pleas for Delaware County, Pennsylvania: (i) Charles Monatt v. PVR Partners, LP, et al. (Case No. 2013-10606); and [(ii) Steven Keene v. James L. Gardner, et al. (Case No. 2013-010723)]. All of the cases name PVR, PVR GP, LLC (“PVR GP”), the current directors of PVR GP, Regency, the General Partner and Merger Sub as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR by agreeing to a transaction with inadequate consideration and unfair terms and pursuant to an inadequate process. The lawsuits allege further that PVR GP, Regency, the General Partner, and Merger Sub aided and abetted the directors of PVR GP in the alleged breach of their fiduciary duties. The Naiditch and Monatt lawsuits allege further that PVR also aided and abetted the directors of PVR GP in the alleged breach of their fiduciary duties. The lawsuits seek, in general, (i) injunctive relief enjoining the transactions contemplated by the merger agreement, (ii) in the event the merger is consummated, rescission or an award of rescissory damages, (iii) an award of plaintiffs’ costs, including reasonable attorneys’ and experts’ fees, (iv) the accounting by the defendants to plaintiffs for all damages caused by the defendants and (v) such further relief as the court deems just and proper. These lawsuits are at a preliminary stage and it is not possible to predict the ultimate outcome of any of these lawsuits. However, PVR, Regency and the other defendants believe that these lawsuits are without merit and intend to defend against them vigorously.
	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, Southern Union’s 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,		31-Dec-12
		2013
	Current	$	40	$	46
	Non-current	192		166
	Total environmental liabilities	$	232	$	212
	During the three and nine months ended September 30, 2013, the Partnership recorded $9 million and $27 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, our subsidiaries utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. Following is a description of price risk management activities by operating entity.
	ETP
	ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of ETP’s derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.
	ETP is also exposed to market risk on natural gas it retains for fees in ETP’s intrastate transportation and storage segment and operational gas sales on ETP’s interstate transportation and storage segment. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	ETP is also exposed to commodity price risk on NGLs and residue gas it retains for fees in ETP’s midstream segment whereby ETP’s subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	ETP’s trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to ETP’s transportation and storage segment’s operations and are netted in cost of products sold in the consolidated statements of operations. Additionally, ETP also has trading activities related to power in ETP’s “All Other” segment which are also netted in cost of products sold. As a result of ETP’s trading activities and the use of derivative financial instruments in ETP’s transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attempts to manage this volatility through the use of daily position and profit and loss reports provided to ETP’s risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in ETP’s commodity risk management policy.
	Derivatives are utilized in ETP’s midstream segment in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. ETP attempts to maintain balanced positions in its marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist.
	The following table details ETP’s outstanding commodity-related derivatives:
		September 30, 2013					December 31, 2012
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	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
	Crude (Bbls) — Futures	(120,000	)		2013		—			—
	Refined Products (Bbls) — Futures	—			—		(98,000	)		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 ETP’s 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.
	Regency
	Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions are prohibited under Regency’s policy.
	The following table details Regency’s outstanding commodity-related derivatives:
		September 30, 2013					December 31, 2012
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	Mark-to-Market Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	15,176,000			2013-2014		8,395,000			2013-2014
	Propane (Gallons):
	Forwards/Swaps	33,642,000			2013-2014		3,318,000			2013
	Natural Gas Liquids (Barrels):
	Forwards/Swaps	144,000			2013-2014		243,000			2013-2014
	WTI Crude Oil (Barrels):
Forwards/Swaps	829,000			2013-2014		356,000			2014
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and floating rate debt. We also manage our interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and floating rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. Southern Union also uses treasury rate locks to manage interest rate risk associated with long term borrowings.
The following table summarizes our interest rate swaps outstanding none of which were designated as hedges for accounting purposes:
						Notional Amount
						Outstanding
Entity		Term		Type(1)		September 30,				December 31, 2012
						2013
ETE		Mar-17		Pay a fixed rate of 1.25% and receive a floating rate		$	—			$	500
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, ETP settled $400 million of 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.
ETP utilizes master-netting agreements and has 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 its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on or about the settlement date for non-exchange traded derivatives. ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of September 30, 2013 would be $7 million, which would be reduced by $2 million, due to the netting feature.
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	39				40				(38		)		(44		)
Current assets held for sale	—				1				—				—
Non-current assets held for sale	—				1				—				—
Current liabilities held for sale	—				—				—				(9		)
Interest rate derivatives	43				55				(112		)		(235		)
Embedded derivatives in Regency Preferred Units	—				—				(23		)		(25		)
	194				207				(268		)		(429		)
Total derivatives	$	210			$	215			$	(271	)		$	(439	)
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 asset (liability)		$	37			$	28			$	(38	)		$	(27	)
Broker cleared derivative contracts		Other current assets (liabilities)		170				149				(159		)		(221		)
				207				177				(197		)		(248		)
Offsetting agreements:
Collateral paid to OTC counterparties		Other current assets (liabilities)		—				—				—				2
Counterparty netting		Price risk management asset (liability)		(32		)		(25		)		32				25
Payments on margin deposit		Other current assets (liabilities)		(15		)		—				34				59
				(47		)		(25		)		66				86
Net derivatives with offsetting agreements				160				152				(131		)		(162		)
Derivatives without offsetting agreements				50				63				(140		)		(277		)
Total derivatives				$	210			$	215			$	(271	)		$	(439	)
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	)		$	11			$	4			$	16
Interest rate derivatives	—				(5		)		—				15
Total	$	(4	)		$	6			$	4			$	31
	Location of Gain/(Loss)		Amount of Gain/(Loss)
	Reclassified from		Reclassified from AOCI into Income
	AOCI into Income		(Effective Portion)
	(Effective Portion)
			Three Months Ended 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			$	25
Total			$	3			$	9			$	5			$	25
	Location of Gain/(Loss)		Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
	Recognized in Income
	on Derivatives
			Three Months Ended 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		$	—			$	10			$	4			$	29
Total			$	—			$	10			$	4			$	29
	Location of Gain/(Loss)		Amount of Gain/(Loss) Recognized in Income on Derivatives
	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		(34		)		(48		)		(20		)		(36		)
Commodity derivatives — Non-Trading	Deferred gas purchases		—				—				(3		)		—
Interest rate derivatives	Gains (losses) on interest rate derivatives		3				(6		)		55				(23		)
Embedded derivatives	Other income		24				2				2				10
Total			$	(18	)		$	(48	)		$	22			$	(56	)

Related_Party_Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	RELATED PARTY TRANSACTIONS:
	The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and on behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.
	In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 18).

Other_Information

Other Information	9 Months Ended
	Sep. 30, 2013
Other Information [Abstract]	'
Other Information	'
	OTHER INFORMATION:
	The tables below present additional detail for certain balance sheet captions.
	Other Current Assets
	Other current assets consisted of the following:
		September 30,		December 31, 2012
		2013
	Deposits paid to vendors	$	55	$	41
	Prepaid expenses and other	266		270
	Total other current assets	$	321	$	311
	Accrued and Other Current Liabilities
	Accrued and other current liabilities consisted of the following:
		September 30,		December 31, 2012
		2013
	Interest payable	$	346	$	334
	Customer advances and deposits	70		61
	Accrued capital expenditures	288		427
	Accrued wages and benefits	200		250
	Taxes payable other than income taxes	294		208
	Income taxes payable	82		41
	Deferred income taxes	243		130
	Deferred revenue	2		—
	Other	397		303
	Total accrued and other current liabilities	$	1,922	$	1,754

Reportable_Segments

Reportable Segments	9 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
Reportable Segments	'
	REPORTABLE SEGMENTS:
	As a result of the Holdco Acquisition in April 2013, our reportable segments were re-evaluated and currently reflect the following reportable segments:
	•Investment in ETP, including the consolidated operations of ETP;
	•	Investment in Regency, including the consolidated operations of Regency; and
	•	Corporate and Other, including the following:
	◦	activities of the Parent Company; and
	◦	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
	Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
	We previously reported net income as a measure of segment performance. Due to the change in our reportable segments described above, the financial information available to our chief operating decision maker to assess the performance is now based on Segment Adjusted EBITDA. Therefore, we have accordingly revised our segment operating performance measure that we report. 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 and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. Based on the change in our segment performance measure, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.
	As discussed in Note 2, Regency completed its acquisition of SUGS on April 30, 2013. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012.
	Eliminations in the tables below include the following:
	•	ETP’s Segment Adjusted EBITDA reflects 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA includes its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star are included in eliminations.
	•	ETP’s Segment Adjusted EBITDA reflects the results of SUGS from March 26, 2012 to April 30, 2013. Because the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also include the results of SUGS from March 26, 2012 to April 30, 2013.
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013					2012
	Segment Adjusted EBITDA:
	Investment in ETP	$	942		$	660		$	2,967				$	1,796
	Investment in Regency	172			141			446					398
	Corporate and Other	(9		)	(7		)	(38		)			(48		)
	Adjustments and Eliminations	(56		)	(40		)	(111		)			(83		)
	Total	1,049			754			3,264					2,063
	Depreciation and amortization	(332		)	(211		)	(962		)			(571		)
	Interest expense, net of interest capitalized	(298		)	(237		)	(913		)			(732		)
	Bridge loan related fees	—			—			—					(62		)
	Gain on deconsolidation of Propane Business	—			—			—					1,057
	Gain on sale of AmeriGas common units	87			—			87			—		—
	Gains (losses) on interest rate derivatives	3			(6		)	55					(23		)
	Non-cash unit-based compensation expense	(16		)	(10		)	(43		)			(34		)
	Unrealized gains (losses) on commodity risk management activities	22			4			45					(43		)
	Losses on extinguishment of debt	—			—			(7		)			(123		)
	Gain on curtailment of other postretirement benefit plans	—			—			—					15
	LIFO valuation adjustments	6			—			22					—
	Equity in earnings of unconsolidated affiliates	38			21			182					118
	Adjusted EBITDA related to unconsolidated affiliates	(165		)	(148		)	(553		)			(429		)
	Adjusted EBITDA related to discontinued operations	(12		)	(32		)	(75		)			(66		)
	Other, net	10			(1		)	6					1
	Income from continuing operations before income tax expense	$	392		$	134		$	1,108				$	1,171
		September 30,			31-Dec-12
		2013
	Total assets:
	Investment in ETP	$	43,556		$	43,230
	Investment in Regency	8,566			8,123
	Corporate and Other	779			707
	Adjustments and Eliminations	(2,858		)	(3,156		)
	Total	$	50,043		$	48,904
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013				2012
	Revenues:
	Investment in ETP:
	Revenues from external customers	$	11,848		$	1,791		$	34,214			$	4,697
	Intersegment revenues	54			11			93				24
		11,902			1,802			34,307				4,721
	Investment in Regency:
	Revenues from external customers	633			526			1,796				1,406
	Intersegment revenues	32			1			48				7
		665			527			1,844				1,413
	Adjustments and Eliminations	(81		)	(225		)	(423		)		(483		)
	Total revenues	$	12,486		$	2,104		$	35,728			$	5,651
	The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Regency.
	Investment in ETP
		Three Months Ended September 30,						Nine Months Ended
September 30,
	2013			2012			2013				2012
Intrastate Transportation and Storage	$	502		$	503		$	1,711			$	1,402
Interstate Transportation and Storage	296			309			973				761
Midstream	683			757			2,021				1,845
NGL Transportation and Services	537			157			1,303				459
Investment in Sunoco Logistics	4,502			—			12,215				—
Retail Marketing	5,297			—			15,805				—
All Other	85			76			279				254
Total revenues	11,902			1,802			34,307				4,721
Less: Intersegment revenues	54			11			93				24
Revenues from external customers	$	11,848		$	1,791		$	34,214			$	4,697
Investment in Regency
	Three Months Ended September 30,						Nine Months Ended
							September 30,
	2013			2012			2013				2012
Gathering and Processing	$	603		$	475		$	1,671			$	1,262
Contract Services	58			47			159				137
Corporate and others	4			5			14				14
Total revenues	665			527			1,844				1,413
Less: Intersegment revenues	32			1			48				7
Revenues from external customers	$	633		$	526		$	1,796			$	1,406

Supplemental_Financial_Stateme

Supplemental Financial Statement Information	9 Months Ended
	Sep. 30, 2013
Supplemental Financial Statement Information	'
Supplemental Financial Statement Information	'
	SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:
	Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:
	BALANCE SHEETS
	(unaudited)
		September 30,				December 31, 2012
		2013
	ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents	$	100			$	9
	Accounts receivable from related companies	7				11
	Other current assets	1				3
	Total current assets	108				23
	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,003				6,094
	INTANGIBLE ASSETS, net	15				19
	GOODWILL	9				9
	NOTE RECEIVABLE FROM AFFILIATE	—				166
	OTHER NON-CURRENT ASSETS, net	50				56
	Total assets	$	4,185			$	6,367
	LIABILITIES AND PARTNERS’ CAPITAL
	CURRENT LIABILITIES:
	Accounts payable	$	8			$	1
	Accounts payable to related companies	27				15
	Interest payable	62				48
	Price risk management liabilities	—				5
	Accrued and other current liabilities	—				1
	Current maturities of long-term debt	4				4
	Total current liabilities	101				74
	LONG-TERM DEBT, less current maturities	2,683				3,840
	PREFERRED UNITS	—				331
	OTHER NON-CURRENT LIABILITIES	1				9
	COMMITMENTS AND CONTINGENCIES
	PARTNERS’ CAPITAL:
	General Partner	(2		)		—
	Limited Partners	1,401				2,125
	Accumulated other comprehensive income (loss)	1				(12		)
	Total partners’ capital	1,400				2,113
	Total liabilities and partners’ capital	$	4,185			$	6,367
	STATEMENTS OF OPERATIONS
	(unaudited)
			Three Months Ended September 30,							Nine Months Ended
										September 30,
			2013				2012			2013			2012
	SELLING, GENERAL AND ADMINISTRATIVE EXPENSES		$	(11	)		$	(7	)	$	(40	)	$	(48	)
	OTHER INCOME (EXPENSE):
	Interest expense, net of interest capitalized		(47		)		(64		)	(164		)	(170		)
	Bridge loan related fees		—				—			—			(62		)
	Gains (losses) on interest rate derivatives		3				(6		)	9			(15		)
	Equity in earnings of unconsolidated affiliates		207				118			573			552
	Other, net		(1		)		(6		)	(11		)	(2		)
	INCOME BEFORE INCOME TAXES		151				35			367			255
	Income tax benefit		—				—			(1		)	—
	NET INCOME		151				35			368			255
	GENERAL PARTNER’S INTEREST IN NET INCOME		1				—			1			1
	LIMITED PARTNERS’ INTEREST IN NET INCOME		$	150			$	35		$	367		$	254
	STATEMENTS OF CASH FLOWS
	(unaudited)
			Nine Months Ended
			September 30,
			2013				2012
	NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$	650			$	406
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Proceeds received in (paid for) acquisitions and other transactions, net		1,332				(1,113		)
	Contributions to affiliate		(8		)		(445		)
Note receivable from affiliate		—				(221		)
Payments received on note receivable from affiliate		166				55
Net cash provided by (used in) investing activities		1,490				(1,724		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		440				2,028
Principal payments on debt		(1,603		)		(141		)
Distributions to partners		(544		)		(491		)
Redemption of Preferred Units		(340		)		—
Debt issuance costs		(2		)		(78		)
Net cash provided by (used in) financing activities		(2,049		)		1,318
DECREASE IN CASH AND CASH EQUIVALENTS		91				—
CASH AND CASH EQUIVALENTS, beginning of period		9				18
CASH AND CASH EQUIVALENTS, end of period		$	100			$	18

Investments_in_Affiliates_Tabl

Investments in Affiliates (Tables)	9 Months Ended
	Sep. 30, 2013
INVESTMENTS IN UNCONSOLIDATED AFFILIATES [Abstract]	'
Investments in and Advances to Affiliates, Schedule of Investments [Text Block]	'
	The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented).
		Three Months Ended September 30,				Nine Months Ended
						September 30,
		2013		2012		2013		2012
	Revenue	$	5,208	$	1,840	$	14,710	$	4,251
	Operating income	163		273		803		807
	Net income	21		111		409		376

Cash_And_Cash_Equivalents_Tabl

Cash And Cash Equivalents (Tables)	9 Months Ended
	Sep. 30, 2013
Supplemental Cash Flow Information [Abstract]	'
Schedule Of Non-Cash Investing and Non-Cash 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	$	260		$	432
	Net gains (losses) from subsidiary common unit transactions	$	(410	)	$	33
	AmeriGas limited partner interest received in Propane Contribution	$	—		$	1,123
	NON-CASH FINANCING ACTIVITIES:
	Issuance of common units in connection with Southern Union Merger	$	—		$	2,354
	Subsidiary issuances of common units in connection with certain acquisitions	$	—		$	112

Inventories_Tables

Inventories (Tables)	9 Months Ended
	Sep. 30, 2013
Inventory, Net [Abstract]	'
Schedule Of Inventory	'
	Inventories consisted of the following:
		September 30,		December 31,
		2013		2012
	Natural gas and NGLs	$	513	$	338
	Crude oil	464		418
	Refined products	517		572
	Other	203		194
	Total inventories	$	1,697	$	1,522

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2013
Fair Value Measurements [Abstract]	'
Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis	'
	The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2013 and December 31, 2012 based on inputs used to derive their fair values:
		Fair Value Measurements at
		30-Sep-13
		Fair Value			Level 1			Level 2			Level 3
		Total
	Assets:
	Interest rate derivatives	$	43		$	—		$	43		$	—
	Commodity derivatives:
	Natural Gas:
	Basis Swaps IFERC/NYMEX	4			4			—			—
	Swing Swaps IFERC	1			—			1			—
	Fixed Swaps/Futures	90			84			6			—
	Options — Calls	1			—			1			—
	Forward Physical Contracts	1			—			1			—
	NGLs — Forwards/Swaps	10			9			1			—
	Power — Forwards	2			—			2			—
	Refined Products — Futures	25			25			—			—
	Total commodity derivatives	134			122			12			—
	Total Assets	$	177		$	122		$	55		$	—
	Liabilities:
	Interest rate derivatives	$	(112	)	$	—		$	(112	)	$	—
	Embedded derivatives in the Regency Preferred Units	(23		)	—			—			(23		)
	Commodity derivatives:
	Condensate — Forward Swaps	(2		)	—			(2		)	—
	Natural Gas:
	Basis Swaps IFERC/NYMEX	(8		)	(8		)	—			—
	Swing Swaps IFERC	(2		)	—			(2		)	—
	Fixed Swaps/Futures	(59		)	(58		)	(1		)	—
	Options — Calls	(1		)	—			(1		)	—
	NGLs — Forwards/Swaps	(10		)	(8		)	(2		)	—
	Power:
	Forwards	(1		)	—			(1		)	—
	Options — Calls	(2		)	—			(2		)	—
	Refined Products — Futures	(16		)	(16		)	—			—
	Crude — Futures	(2		)	(2		)	—			—
	Total commodity derivatives	(103		)	(92		)	(11		)	—
	Total Liabilities	$	(238	)	$	(92	)	$	(123	)	$	(23	)
		Fair Value Measurements at
		31-Dec-12
		Fair Value			Level 1			Level 2			Level 3
		Total
	Assets:
	Interest rate derivatives	$	55		$	—		$	55		$	—
	Commodity derivatives:
	Condensate — Forward Swaps	2			—			2			—
	Natural Gas:
	Basis Swaps IFERC/NYMEX	11			11			—			—
	Swing Swaps IFERC	3			—			3			—
	Fixed Swaps/Futures	98			94			4			—
	Options — Calls	3			—			3			—
	Options — Puts	1			—			1			—
	Forward Physical Contracts	1			—			1			—
	NGLs — Swaps	2			1			1			—
	Power:
	Forwards	27			—			27			—
	Futures	1			1			—			—
	Options — Calls	2			—			2			—
	Refined Products — Futures	5			1			4			—
	Total commodity derivatives	156			108			48			—
	Total Assets	$	211		$	108		$	103		$	—
	Liabilities:
	Interest rate derivatives	$	(235	)	$	—		$	(235	)	$	—
	Preferred Units	(331		)	—			—			(331		)
Embedded derivatives in the Regency Preferred Units	(25		)	—			—			(25		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)	(18		)	—			—
Swing Swaps IFERC	(2		)	—			(2		)	—
Fixed Swaps/Futures	(103		)	(94		)	(9		)	—
Options — Calls	(3		)	—			(3		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Swaps	(4		)	(3		)	(1		)	—
Power:
Forwards	(27		)	—			(27		)	—
Futures	(2		)	(2		)	—			—
Refined Products — Futures	(8		)	(1		)	(7		)	—
Total commodity derivatives	(168		)	(118		)	(50		)	—
Total Liabilities	$	(759	)	$	(118	)	$	(285	)	$	(356	)
Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis	'
	The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the nine months ended September 30, 2013. There were no transfers between the fair value hierarchy levels during the nine months ended September 30, 2013 or 2012.
	Balance, December 31, 2012	$	(356	)
	Realized loss included in other income (expense)	(9		)
	Net unrealized gain included in other income (expense)	2
	Redemption of Preferred Units	340
	Balance, September 30, 2013	$	(23	)

Net_Income_per_Limited_Partner1

Net Income per Limited Partner Unit (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Reconciliation Of Net Income And Weighted Average Units	'
	A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows:
		Three Months Ended September 30,					Nine Months Ended
							September 30,
		2013		2012			2013			2012
	Income from continuing operations	$	343	$	108		$	972		$	1,138
	Less: Income from continuing operations attributable to noncontrolling interest	195		45			623			860
	Income from continuing operations, net of noncontrolling interest	148		63			349			278
	Less: General Partner’s interest in income from continuing operations	1		—			1			—
	Income from continuing operations available to Limited Partners	$	147	$	63		$	348		$	278
	Basic Income from Continuing Operations per Limited Partner Unit:
	Weighted average limited partner units	280.7		280			280.4			262.3
	Basic income from continuing operations per Limited Partner unit	$	0.52	$	0.23		$	1.24		$	1.06
	Basic income (loss) from discontinued operations per Limited Partner unit	$	0.02	$	(0.10	)	$	0.07		$	(0.09	)
	Diluted Income from Continuing Operations per Limited Partner Unit:
	Income from continuing operations available to Limited Partners	$	147	$	63		$	348		$	278
	Dilutive effect of equity-based compensation of subsidiaries	—		—			(1		)	(1		)
	Diluted income from continuing operations available to Limited Partners	$	147	$	63		$	347		$	277
	Weighted average limited partner units	280.7		280			280.4			262.3
	Diluted income from continuing operations per Limited Partner unit	$	0.52	$	0.23		$	1.24		$	1.06
	Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.02	$	(0.10	)	$	0.07		$	(0.09	)

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 ETE Common Units

'

The change in ETE Common Units during the nine months ended September 30, 2013 was as follows:

Number of

Units

Outstanding at December 31, 2012

280

Issuance of restricted units under equity incentive plans

0.8

Outstanding at September 30, 2013

280.8

Accumulated Other Comprehensive Income

'

The following table presents the components of accumulated other comprehensive income (loss), net of tax:

September 30,

December 31, 2012

2013

Net gains (losses) on commodity related hedges

$

—

$

(3

)

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

(22

)

Amounts attributable to noncontrolling interest

(2

)

10

Total accumulated other comprehensive income (loss), net of tax

$

1

$

(12

)

Parent Company [Member]

'

Quarterly Distributions Of Available Cash

'

Following are distributions declared and/or paid by us subsequent to December 31, 2012:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2012

February 7, 2013

February 19, 2013

$

0.635

March 31, 2013

May 6, 2013

May 17, 2013

0.645

June 30, 2013

August 5, 2013

August 19, 2013

0.655

30-Sep-13

November 4, 2013

November 19, 2013

0.6725

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

31-Dec-12

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

August 14, 2013

0.89375

30-Sep-13

November 4, 2013

November 14, 2013

0.905

Regency [Member]

'

Quarterly Distributions Of Available Cash

'

Following are distributions declared and/or paid by Regency subsequent to December 31, 2012:

Quarter Ended

Record Date

Payment Date

Rate

31-Dec-12

February 7, 2013

February 14, 2013

$

0.46

31-Mar-13

May 6, 2013

May 13, 2013

0.46

30-Jun-13

August 5, 2013

August 14, 2013

0.465

30-Sep-13

November 4, 2013

November 14, 2013

0.47

Sunoco Logistics [Member]

'

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

31-Dec-12

February 8, 2013

February 14, 2013

$

0.545

31-Mar-13

May 9, 2013

May 15, 2013

0.5725

30-Jun-13

August 8, 2013

August 14, 2013

0.6

30-Sep-13

November 8, 2013

November 14, 2013

0.63

Income_Taxes_Tables

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
	The following 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	$	49		$	26		$	136		$	33
	Effective tax rate	13		%	19		%	12		%	3		%

Retirement_Benefits_Tables

Retirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2013
BENEFITS [Abstract]	'
Schedule of Net Benefit Costs [Table Text Block]	'
	The following table sets 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 Exit Cost [Line Items]	'
Environmental Exit Costs by Cost	'
	The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable.  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,		31-Dec-12
		2013
	Current	$	40	$	46
	Non-current	192		166
	Total environmental liabilities	$	232	$	212

Price_Risk_Management_Assets_A1

Price Risk Management Assets And Liabilities (Tables)	9 Months Ended
	Sep. 30, 2013
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	'
		Location of Gain/(Loss)		Amount of Gain/(Loss) Recognized in Income on Derivatives
		Recognized in Income
		on Derivatives
				Three Months Ended 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		(34		)		(48		)		(20		)		(36		)
	Commodity derivatives — Non-Trading	Deferred gas purchases		—				—				(3		)		—
	Interest rate derivatives	Gains (losses) on interest rate derivatives		3				(6		)		55				(23		)
	Embedded derivatives	Other income		24				2				2				10
	Total			$	(18	)		$	(48	)		$	22			$	(56	)
Interest Rate Swaps Outstanding	'
	The following table summarizes our interest rate swaps outstanding none of which were designated as hedges for accounting purposes:
							Notional Amount
							Outstanding
	Entity		Term		Type(1)		September 30,				December 31, 2012
							2013
	ETE		Mar-17		Pay a fixed rate of 1.25% and receive a floating rate		$	—			$	500
	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	39				40				(38		)		(44		)
	Current assets held for sale	—				1				—				—
	Non-current assets held for sale	—				1				—				—
	Current liabilities held for sale	—				—				—				(9		)
	Interest rate derivatives	43				55				(112		)		(235		)
	Embedded derivatives in Regency Preferred Units	—				—				(23		)		(25		)
		194				207				(268		)		(429		)
	Total derivatives	$	210			$	215			$	(271	)		$	(439	)
	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 asset (liability)		$	37			$	28			$	(38	)		$	(27	)
	Broker cleared derivative contracts		Other current assets (liabilities)		170				149				(159		)		(221		)
					207				177				(197		)		(248		)
	Offsetting agreements:
	Collateral paid to OTC counterparties		Other current assets (liabilities)		—				—				—				2
	Counterparty netting		Price risk management asset (liability)		(32		)		(25		)		32				25
	Payments on margin deposit		Other current assets (liabilities)		(15		)		—				34				59
					(47		)		(25		)		66				86
	Net derivatives with offsetting agreements				160				152				(131		)		(162		)
	Derivatives without offsetting agreements				50				63				(140		)		(277		)
	Total derivatives				$	210			$	215			$	(271	)		$	(439	)
Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives	'
	The following tables summarize the amounts recognized with respect to our derivative financial instruments:
		Change in Value Recognized in OCI on Derivatives
		(Effective Portion)
		Three Months Ended September 30,								Nine Months Ended
										September 30,
		2013				2012				2013				2012
	Derivatives in cash flow hedging relationships:
	Commodity derivatives	$	(4	)		$	11			$	4			$	16
	Interest rate derivatives	—				(5		)		—				15
	Total	$	(4	)		$	6			$	4			$	31
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
		Location of Gain/(Loss)		Amount of Gain/(Loss)
		Reclassified from		Reclassified from AOCI into Income
		AOCI into Income		(Effective Portion)
		(Effective Portion)
				Three Months Ended 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			$	25
	Total			$	3			$	9			$	5			$	25
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	'
		Location of Gain/(Loss)		Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Recognized in Income
		on Derivatives
				Three Months Ended 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		$	—			$	10			$	4			$	29
	Total			$	—			$	10			$	4			$	29
ETP [Member]	'
Outstanding Commodity-Related Derivatives	'
	The following table details ETP’s outstanding commodity-related derivatives:
		September 30, 2013					December 31, 2012
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	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
	Crude (Bbls) — Futures	(120,000	)		2013		—			—
	Refined Products (Bbls) — Futures	—			—		(98,000	)		2013
	(1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations
Regency [Member]	'
Outstanding Commodity-Related Derivatives	'
	The following table details Regency’s outstanding commodity-related derivatives:
		September 30, 2013					December 31, 2012
		Notional			Maturity		Notional			Maturity
		Volume					Volume
	Mark-to-Market Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	15,176,000			2013-2014		8,395,000			2013-2014
	Propane (Gallons):
	Forwards/Swaps	33,642,000			2013-2014		3,318,000			2013
	Natural Gas Liquids (Barrels):
	Forwards/Swaps	144,000			2013-2014		243,000			2013-2014
	WTI Crude Oil (Barrels):
	Forwards/Swaps	829,000			2013-2014		356,000			2014

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,		December 31, 2012
		2013
	Deposits paid to vendors	$	55	$	41
	Prepaid expenses and other	266		270
	Total other current assets	$	321	$	311
Accrued And Other Current Liabilities	'
	Accrued and other current liabilities consisted of the following:
		September 30,		December 31, 2012
		2013
	Interest payable	$	346	$	334
	Customer advances and deposits	70		61
	Accrued capital expenditures	288		427
	Accrued wages and benefits	200		250
	Taxes payable other than income taxes	294		208
	Income taxes payable	82		41
	Deferred income taxes	243		130
	Deferred revenue	2		—
	Other	397		303
	Total accrued and other current liabilities	$	1,922	$	1,754

Reportable_Segments_Tables

Reportable Segments (Tables)	9 Months Ended
	Sep. 30, 2013
Operating Segments [Member]	'
Financial Information By Segment	'
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013					2012
	Segment Adjusted EBITDA:
	Investment in ETP	$	942		$	660		$	2,967				$	1,796
	Investment in Regency	172			141			446					398
	Corporate and Other	(9		)	(7		)	(38		)			(48		)
	Adjustments and Eliminations	(56		)	(40		)	(111		)			(83		)
	Total	1,049			754			3,264					2,063
	Depreciation and amortization	(332		)	(211		)	(962		)			(571		)
	Interest expense, net of interest capitalized	(298		)	(237		)	(913		)			(732		)
	Bridge loan related fees	—			—			—					(62		)
	Gain on deconsolidation of Propane Business	—			—			—					1,057
	Gain on sale of AmeriGas common units	87			—			87			—		—
	Gains (losses) on interest rate derivatives	3			(6		)	55					(23		)
	Non-cash unit-based compensation expense	(16		)	(10		)	(43		)			(34		)
	Unrealized gains (losses) on commodity risk management activities	22			4			45					(43		)
	Losses on extinguishment of debt	—			—			(7		)			(123		)
	Gain on curtailment of other postretirement benefit plans	—			—			—					15
	LIFO valuation adjustments	6			—			22					—
	Equity in earnings of unconsolidated affiliates	38			21			182					118
	Adjusted EBITDA related to unconsolidated affiliates	(165		)	(148		)	(553		)			(429		)
	Adjusted EBITDA related to discontinued operations	(12		)	(32		)	(75		)			(66		)
	Other, net	10			(1		)	6					1
	Income from continuing operations before income tax expense	$	392		$	134		$	1,108				$	1,171
Assets Segments [Member]	'
Financial Information By Segment	'
		September 30,			31-Dec-12
		2013
	Total assets:
	Investment in ETP	$	43,556		$	43,230
	Investment in Regency	8,566			8,123
	Corporate and Other	779			707
	Adjustments and Eliminations	(2,858		)	(3,156		)
	Total	$	50,043		$	48,904
Sales Revenue, Segment [Member]	'
Financial Information By Segment	'
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013				2012
	Revenues:
	Investment in ETP:
	Revenues from external customers	$	11,848		$	1,791		$	34,214			$	4,697
	Intersegment revenues	54			11			93				24
		11,902			1,802			34,307				4,721
	Investment in Regency:
	Revenues from external customers	633			526			1,796				1,406
	Intersegment revenues	32			1			48				7
		665			527			1,844				1,413
	Adjustments and Eliminations	(81		)	(225		)	(423		)		(483		)
	Total revenues	$	12,486		$	2,104		$	35,728			$	5,651
Investment In ETP [Member]	'
Revenue from External Customers by Products and Services [Table Text Block]	'
	Investment in ETP
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013				2012
	Intrastate Transportation and Storage	$	502		$	503		$	1,711			$	1,402
	Interstate Transportation and Storage	296			309			973				761
	Midstream	683			757			2,021				1,845
	NGL Transportation and Services	537			157			1,303				459
	Investment in Sunoco Logistics	4,502			—			12,215				—
	Retail Marketing	5,297			—			15,805				—
	All Other	85			76			279				254
	Total revenues	11,902			1,802			34,307				4,721
	Less: Intersegment revenues	54			11			93				24
	Revenues from external customers	$	11,848		$	1,791		$	34,214			$	4,697
Investment In Regency [Member]	'
Revenue from External Customers by Products and Services [Table Text Block]	'
	Investment in Regency
		Three Months Ended September 30,						Nine Months Ended
								September 30,
		2013			2012			2013				2012
	Gathering and Processing	$	603		$	475		$	1,671			$	1,262
	Contract Services	58			47			159				137
	Corporate and others	4			5			14				14
	Total revenues	665			527			1,844				1,413
	Less: Intersegment revenues	32			1			48				7
	Revenues from external customers	$	633		$	526		$	1,796			$	1,406

Supplemental_Financial_Stateme1

Supplemental Financial Statement Information (Tables)	9 Months Ended
	Sep. 30, 2013
Schedule Of Balance Sheets	'
	BALANCE SHEETS
	(unaudited)
		September 30,				December 31, 2012
		2013
	ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents	$	100			$	9
	Accounts receivable from related companies	7				11
	Other current assets	1				3
	Total current assets	108				23
	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,003				6,094
	INTANGIBLE ASSETS, net	15				19
	GOODWILL	9				9
	NOTE RECEIVABLE FROM AFFILIATE	—				166
	OTHER NON-CURRENT ASSETS, net	50				56
	Total assets	$	4,185			$	6,367
	LIABILITIES AND PARTNERS’ CAPITAL
	CURRENT LIABILITIES:
	Accounts payable	$	8			$	1
	Accounts payable to related companies	27				15
	Interest payable	62				48
	Price risk management liabilities	—				5
	Accrued and other current liabilities	—				1
	Current maturities of long-term debt	4				4
	Total current liabilities	101				74
	LONG-TERM DEBT, less current maturities	2,683				3,840
	PREFERRED UNITS	—				331
	OTHER NON-CURRENT LIABILITIES	1				9
	COMMITMENTS AND CONTINGENCIES
	PARTNERS’ CAPITAL:
	General Partner	(2		)		—
	Limited Partners	1,401				2,125
	Accumulated other comprehensive income (loss)	1				(12		)
	Total partners’ capital	1,400				2,113
	Total liabilities and partners’ capital	$	4,185			$	6,367
Schedule Of Statements Of Operations	'
	STATEMENTS OF OPERATIONS
	(unaudited)
			Three Months Ended September 30,							Nine Months Ended
										September 30,
			2013				2012			2013			2012
	SELLING, GENERAL AND ADMINISTRATIVE EXPENSES		$	(11	)		$	(7	)	$	(40	)	$	(48	)
	OTHER INCOME (EXPENSE):
	Interest expense, net of interest capitalized		(47		)		(64		)	(164		)	(170		)
	Bridge loan related fees		—				—			—			(62		)
	Gains (losses) on interest rate derivatives		3				(6		)	9			(15		)
	Equity in earnings of unconsolidated affiliates		207				118			573			552
	Other, net		(1		)		(6		)	(11		)	(2		)
	INCOME BEFORE INCOME TAXES		151				35			367			255
	Income tax benefit		—				—			(1		)	—
	NET INCOME		151				35			368			255
	GENERAL PARTNER’S INTEREST IN NET INCOME		1				—			1			1
	LIMITED PARTNERS’ INTEREST IN NET INCOME		$	150			$	35		$	367		$	254
Parent Company [Member]	'
Schedule Of Statements Of Cash Flows	'
	STATEMENTS OF CASH FLOWS
	(unaudited)
			Nine Months Ended
			September 30,
			2013				2012
	NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$	650			$	406
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Proceeds received in (paid for) acquisitions and other transactions, net		1,332				(1,113		)
	Contributions to affiliate		(8		)		(445		)
	Note receivable from affiliate		—				(221		)
	Payments received on note receivable from affiliate		166				55
	Net cash provided by (used in) investing activities		1,490				(1,724		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from borrowings		440				2,028
	Principal payments on debt		(1,603		)		(141		)
	Distributions to partners		(544		)		(491		)
	Redemption of Preferred Units		(340		)		—
	Debt issuance costs		(2		)		(78		)
	Net cash provided by (used in) financing activities		(2,049		)		1,318
	DECREASE IN CASH AND CASH EQUIVALENTS		91				—
	CASH AND CASH EQUIVALENTS, beginning of period		9				18
	CASH AND CASH EQUIVALENTS, end of period		$	100			$	18

Operations_And_Organization_Na

Operations And Organization Narrative (Details)	9 Months Ended
	Sep. 30, 2013
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%
Holdco [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	60.00%
ETP [Member] | Lone Star L.L.C. [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	70.00%
ETP [Member] | Holdco [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Fayetteville Express Pipeline, LLC [Member] | FEP [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
FGT [Member] | FEP [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Regency [Member] | Lone Star L.L.C. [Member]	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	30.00%

Acquisitions_Narrative_Details

Acquisitions Narrative (Details) (USD $)

Oct. 10, 2013

Apr. 30, 2013

Oct. 04, 2012

Oct. 05, 2012

Apr. 30, 2013

Apr. 30, 2013

Apr. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

SUGS Contribution [Member]

Sunoco Merger [Member]

Sunoco Merger [Member]

Holdco Acquisition [Member]

Southern Union [Member]

ETP [Member]

Holdco [Member]

ETE [Member]

ETP [Member]

Missouri Gas Energy [Member]

New England Gas Company [Member]

SUGS Contribution [Member]

SUGS Contribution [Member]

Holdco [Member]

Holdco [Member]

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, Equity Interest Issued or Issuable, Number of Shares

'

31,400,000

55,000,000

'

'

'

'

'

'

'

'

'

Regency Class F Units to be Issued in SUGS Contribution

'

6,300,000

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Current Assets, Cash and Cash Equivalents

'

'

'

'

'

463,000,000

30,000,000

'

'

'

'

'

Estimated Closing Adjustments

'

'

'

'

68,000,000

'

'

'

'

'

'

'

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

'

'

'

'

'

'

'

60.00%

60.00%

100.00%

'

'

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares (instant)

'

'

'

'

49,500,000

'

'

'

'

'

'

'

Business Combination, Consideration Transferred

'

'

'

2,600,000,000

'

'

'

'

'

'

'

'

Business Acquisition, Cost of Acquired Entity, Cash Paid

'

'

'

'

1,400,000,000

'

'

'

'

'

'

'

Proposed Business Combination, Acquisition Related Costs

40,000,000

'

'

'

'

'

'

'

'

'

'

'

Proposed Business Acquisition, Cost of Acquired Entity, Purchase Price

5,600,000,000

'

'

'

'

'

'

'

'

'

'

'

Proposed Business Acquisition, Cost of Acquired Entity, Liabilities Incurred

$1,800,000,000

'

'

'

'

'

'

'

'

'

'

'

Number Of Share Received In Exchange Of Each Share

1.02

'

'

'

'

'

'

'

'

'

'

'

Investments_in_Affiliates_Narr

Investments in Affiliates Narrative (Details) (USD $)	9 Months Ended					9 Months Ended					9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Jan. 31, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
			AmeriGas [Member]	AmeriGas [Member]	Citrus [Member]	FGT [Member]	Fayetteville Express Pipeline, LLC [Member]	RIGS Haynesville Partnership Co. [Member]	Midcontinent Express Pipeline, LLC [Member]	PES Joint Venture [Member]	AmeriGas [Member]
Schedule of Equity Method Investments [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Investment Owned, Balance, Shares	'	'	22	30	'	'	'	'	'	'	'
AmeriGas common units sold by ETP	7.5	'	'	'	'	'	'	'	'	'	'
Proceeds from ETP's sale of AmeriGas common units	$346	$0	'	'	'	'	'	'	'	'	$346
Interest ownership	'	'	'	'	50.00%	'	50.00%	49.99%	50.00%	30.00%	'
Percentage Ownership Operating Facility	'	'	'	'	'	100.00%	'	'	'	'	'

Investments_in_Affiliates_Tabl1

Investments in Affiliates Table - Selected I/S Data (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
Schedule of Equity Method Investments [Line Items]	'	'	'	'
Revenue	$5,208	$1,840	$14,710	$4,251
Operating income	163	273	803	807
Net income	$21	$111	$409	$376

Cash_And_Cash_Equivalents_Tabl1

Cash And Cash Equivalents Table - Schedule of Non-Cash Investing & 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	$260	$432
Net gains (losses) from subsidiary common unit transactions	-410	33
AmeriGas limited partner interest received in Propane Contribution	0	1,123
NON-CASH FINANCING ACTIVITIES:	'	'
Issuance of common units in connection with Southern Union Merger	0	112
Southern Union Merger [Member]	'	'
NON-CASH FINANCING ACTIVITIES:	'	'
Issuance of common units in connection with Southern Union Merger	$0	$2,354

Inventories_Table_Inventory_Ba

Inventories Table - Inventory Balances (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Inventory, Net [Abstract]	'	'
Natural gas and NGLs	$513	$338
Crude oil	464	418
Refined products	517	572
Other	203	194
Total inventories	$1,697	$1,522

Fair_Value_Measurements_Narrat

Fair Value Measurements Narrative (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Billions, unless otherwise specified
Fair Value Measurements [Abstract]	'	'
Debt obligations, fair value	$22.96	$24.15
Long-term Debt	$22.31	$22.05

Fair_Value_Measurements_Table_

Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Interest rate derivatives, Asset Fair Value	$43	$55
Commodity derivatives, Asset Fair Value	134	156
Total Assets	177	211
Interest rate derivatives, Liability Fair Value	-112	-235
Preferred Units	0	-331
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	-23	-25
Commodity derivatives, Liability Fair Value	-103	-168
Total Liabilities	-238	-759
Level 1 [Member]	'	'
Interest rate derivatives, Asset Fair Value	0	0
Commodity derivatives, Asset Fair Value	122	108
Total Assets	122	108
Interest rate derivatives, Liability Fair Value	0	0
Preferred Units	'	0
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	0	0
Commodity derivatives, Liability Fair Value	-92	-118
Total Liabilities	-92	-118
Level 2 [Member]	'	'
Interest rate derivatives, Asset Fair Value	43	55
Commodity derivatives, Asset Fair Value	12	48
Total Assets	55	103
Interest rate derivatives, Liability Fair Value	-112	-235
Preferred Units	'	0
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	0	0
Commodity derivatives, Liability Fair Value	-11	-50
Total Liabilities	-123	-285
Level 3 [Member]	'	'
Interest rate derivatives, Asset Fair Value	0	0
Commodity derivatives, Asset Fair Value	0	0
Total Assets	0	0
Interest rate derivatives, Liability Fair Value	0	0
Preferred Units	'	-331
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	-23	-25
Commodity derivatives, Liability Fair Value	0	0
Total Liabilities	-23	-356
Commodity Derivatives - Condensate [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	'	2
Commodity derivatives, Liability Fair Value	-2	'
Commodity Derivatives - Condensate [Member] | Level 1 [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	'	0
Commodity derivatives, Liability Fair Value	0	'
Commodity Derivatives - Condensate [Member] | Level 2 [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	'	2
Commodity derivatives, Liability Fair Value	-2	'
Commodity Derivatives - Condensate [Member] | Level 3 [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	'	0
Commodity derivatives, Liability Fair Value	0	'
Commodity Derivatives - Refined Products [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	25	5
Commodity derivatives, Liability Fair Value	-16	-8
Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	25	1
Commodity derivatives, Liability Fair Value	-16	-1
Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	0	4
Commodity derivatives, Liability Fair Value	0	-7
Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - Power [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	2	27
Commodity derivatives, Liability Fair Value	-1	-27
Commodity Derivatives - Power [Member] | Call Option [Member]	'	'
Commodity derivatives, Asset Fair Value	'	2
Commodity derivatives, Liability Fair Value	-2	'
Commodity Derivatives - Power [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	'	1
Commodity derivatives, Liability Fair Value	'	-2
Commodity Derivatives - Power [Member] | Level 1 [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - Power [Member] | Level 1 [Member] | Call Option [Member]	'	'
Commodity derivatives, Asset Fair Value	'	0
Commodity derivatives, Liability Fair Value	0	'
Commodity Derivatives - Power [Member] | Level 1 [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	'	1
Commodity derivatives, Liability Fair Value	'	-2
Commodity Derivatives - Power [Member] | Level 2 [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	2	27
Commodity derivatives, Liability Fair Value	-1	-27
Commodity Derivatives - Power [Member] | Level 2 [Member] | Call Option [Member]	'	'
Commodity derivatives, Asset Fair Value	'	2
Commodity derivatives, Liability Fair Value	-2	'
Commodity Derivatives - Power [Member] | Level 2 [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	'	0
Commodity derivatives, Liability Fair Value	'	0
Commodity Derivatives - Power [Member] | Level 3 [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - Power [Member] | Level 3 [Member] | Call Option [Member]	'	'
Commodity derivatives, Asset Fair Value	'	0
Commodity derivatives, Liability Fair Value	0	'
Commodity Derivatives - Power [Member] | Level 3 [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	'	0
Commodity derivatives, Liability Fair Value	'	0
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member]	'	'
Commodity derivatives, Asset Fair Value	4	11
Commodity derivatives, Liability Fair Value	-8	-18
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]	'	'
Commodity derivatives, Asset Fair Value	1	3
Commodity derivatives, Liability Fair Value	-2	-2
Commodity Derivatives - Natural Gas [Member] | Call Option [Member]	'	'
Commodity derivatives, Asset Fair Value	1	3
Commodity derivatives, Liability Fair Value	-1	-3
Commodity Derivatives - Natural Gas [Member] | Options - Puts [Member]	'	'
Commodity derivatives, Asset Fair Value	'	1
Commodity derivatives, Liability Fair Value	'	-1
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	1	1
Commodity Derivatives - Natural Gas [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	90	98
Commodity derivatives, Liability Fair Value	-59	-103
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Basis Swaps IFERC/NYMEX [Member]	'	'
Commodity derivatives, Asset Fair Value	4	11
Commodity derivatives, Liability Fair Value	-8	-18
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Swing Swaps IFERC [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Call Option [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Options - Puts [Member]	'	'
Commodity derivatives, Asset Fair Value	'	0
Commodity derivatives, Liability Fair Value	'	0
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	84	94
Commodity derivatives, Liability Fair Value	-58	-94
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Basis Swaps IFERC/NYMEX [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Swing Swaps IFERC [Member]	'	'
Commodity derivatives, Asset Fair Value	1	3
Commodity derivatives, Liability Fair Value	-2	-2
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Call Option [Member]	'	'
Commodity derivatives, Asset Fair Value	1	3
Commodity derivatives, Liability Fair Value	-1	-3
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Options - Puts [Member]	'	'
Commodity derivatives, Asset Fair Value	'	1
Commodity derivatives, Liability Fair Value	'	-1
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	1	1
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	6	4
Commodity derivatives, Liability Fair Value	-1	-9
Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Basis Swaps IFERC/NYMEX [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Swing Swaps IFERC [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Call Option [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Options - Puts [Member]	'	'
Commodity derivatives, Asset Fair Value	'	0
Commodity derivatives, Liability Fair Value	'	0
Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Forward Physical Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Future [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	10	2
Commodity derivatives, Liability Fair Value	-10	-4
Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	9	1
Commodity derivatives, Liability Fair Value	-8	-3
Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	1	1
Commodity derivatives, Liability Fair Value	-2	-1
Commodity Derivatives - NGLs [Member] | Level 3 [Member] | Forward Swaps [Member]	'	'
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Crude Oil [Member] | Future [Member]	'	'
Commodity derivatives, Liability Fair Value	-2	'
Crude Oil [Member] | Level 1 [Member] | Future [Member]	'	'
Commodity derivatives, Liability Fair Value	-2	'
Crude Oil [Member] | Level 2 [Member] | Future [Member]	'	'
Commodity derivatives, Liability Fair Value	0	'
Crude Oil [Member] | Level 3 [Member] | Future [Member]	'	'
Commodity derivatives, Liability Fair Value	$0	'

Fair_Value_Measurements_Table_1

Fair Value Measurements Table - Reconciliation of Level 3 Derivatives (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Dec. 31, 2012
			Level 3 [Member]	Level 3 [Member]
			Fair Value, Measurements, Recurring [Member]	Fair Value, Measurements, Recurring [Member]
Balance, December 31, 2012	'	'	($23)	($356)
Realized loss included in other income (expense)	-9	'	'	'
Net unrealized gain included in other income (expense)	-2	'	'	'
Redemption of Preferred Units	340	0	'	'
Balance, September 30, 2013	'	'	($23)	($356)

Net_Income_per_Limited_Partner2

Net Income per Limited Partner Unit Table - Income Reconciliation (Details) (USD $)	3 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, 2012
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]	'	'	'	'
Income from continuing operations	$343	$108	$972	$1,138
Income (Loss) from Continuing Operations Attributable to Noncontrolling Interest	195	45	623	860
Income from continuing operations, net of noncontrolling interest	148	63	349	278
General Partner’s interest in income from continuing operations	-1	0	-1	0
Income from continuing operations available to Limited Partners	147	63	348	278
Less: General Partner’s interest in income from continuing operations	1	0	1	0
Basic Income from Continuing Operations per Limited Partner Unit:	'	'	'	'
Weighted average Limited Partner units	280.7	280	280.4	262.3
Basic income from continuing operations per Limited Partner unit	0.52	0.23	1.24	1.06
Basic income from discontinued operations per Limited Partner unit	$0.02	($0.10)	$0.07	($0.09)
Diluted Income from Continuing Operations per Limited Partner Unit:	'	'	'	'
Dilutive effect of equity-based compensation of subsidiaries	0	0	-1	-1
Diluted net income available to Limited Partners	$147	$63	$347	$277
Weighted average Limited Partner units	280.7	280	280.4	262.3
Diluted income from continuing operations per Limited Partner unit	0.52	0.23	1.24	1.06
Diluted income from discontinued operations per Limited Partner unit	$0.02	($0.10)	$0.07	($0.09)

Debt_Obligations_Narrative_Sen

Debt Obligations Narrative - Senior Notes (Details) (USD $)

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Jun. 24, 2013

Sep. 30, 2013

Jan. 31, 2013

Jan. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Jan. 31, 2013

Jan. 31, 2013

Jan. 31, 2013

Jan. 31, 2013

Sep. 30, 2013

Jun. 24, 2013

Jun. 24, 2013

Jun. 24, 2013

ETP [Member]

ETP [Member]

Sunoco Logistics [Member]

ETE 7.5% Senior Notes due 2020 [Member]

ETE Credit Facility [Member]

Regency 4.50% Senior Notes Due 2023 [Member]

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]

Regency Senior Notes [Member]

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

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

Junior Subordinated Debt [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

'

'

'

'

'

'

'

'

'

$600,000,000

'

'

'

'

'

'

'

'

Senior Notes

'

'

'

'

'

'

'

1,800,000,000

'

'

800,000,000

450,000,000

350,000,000

350,000,000

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

7.50%

'

4.50%

3.60%

5.15%

3.45%

4.95%

9.38%

7.60%

8.25%

'

Tender offer repurchase amount

'

'

'

'

'

'

'

400,000,000

'

'

'

'

'

'

'

'

'

'

Proceeds from Issuance of Long-term Debt

'

9,768,000,000

9,081,000,000

'

'

'

'

'

'

'

'

'

'

'

178,000,000

'

'

'

Debt Instrument, Increase, Accrued Interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

'

'

'

Repayments of Long-term Debt

455,000,000

9,439,000,000

6,144,000,000

'

'

'

'

'

'

'

'

'

'

'

163,000,000

'

'

'

Proceeds from Issuance of Senior Long-term Debt

'

'

'

'

1,470,000,000

1,240,000,000

691,000,000

'

'

'

'

'

'

'

'

'

'

'

ETP Note Exchange

'

'

'

1,090,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity

'

'

'

'

'

'

'

'

$600,000,000

'

'

'

'

'

'

'

'

'

Percent of SUG Notes Exchanged for ETP Notes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

77.00%

89.00%

91.00%

Debt_Obligations_Narrative_ETE

Debt Obligations Narrative - ETE Credit Facility (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
			ETE Senior Secured Revolving Credit Facilities [Member]	LIBOR [Member]	Base Rate Loans [Member]	ETE Senior Secured Term Loan [Member]	Holdco [Member]	Holdco [Member]
								ETE [Member]
Secured Debt	$2,000,000,000	'	'	'	'	'	'	'
Debt Instrument, Basis Spread on Variable Rate	'	'	'	3.00%	2.00%	'	'	'
Outstanding borrowings	0	'	0	'	'	'	'	'
Line of Credit Facility, Remaining Borrowing Capacity	'	'	200,000,000	'	'	'	'	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	'	'	'	'	'	'	60.00%	60.00%
Proceeds from Issuance or Sale of Equity	'	'	'	'	'	1,100,000,000	'	'
Long-term Debt	$22,310,000,000	$22,050,000,000	'	'	'	$900,000,000	'	'

Debt_Obligations_Narrative_Reg

Debt Obligations Narrative - Regency Credit Facility (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Outstanding borrowings	$0
Regency Credit Facility [Member]	'
Outstanding borrowings	176
Letters of Credit Outstanding, Amount	15
Amount available for future borrowings	1,010
Weighted average interest rate on amount outstanding	2.19%
Line of Credit Facility, Maximum Borrowing Capacity	1,200
Regency Credit Facility [Member]	'
Line of Credit Facility, Maximum Borrowing Capacity	300
5.75% Senior Notes Due 2020 [Member]	'
Debt Instrument, Face Amount	400
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Regency Credit Facility [Member]	'
Repayments of Lines of Credit	$394

Debt_Obligations_Narrative_ETP

Debt Obligations Narrative - ETP Credit Facility (Details) (USD $)	1 Months Ended	9 Months Ended						1 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Jan. 31, 2013
				4.15% Senior Notes due October 1, 2020 [Member]	ETP Credit Facility [Member]	4.9% Senior Notes due February 1, 2024 [Member]	5.95% Senior Notes due October 1, 2043 [Member]	ETP [Member]	ETP [Member]
Senior Notes	'	'	'	$700	'	$350	$450	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	'	'	4.15%	'	4.90%	5.95%	'	'
Outstanding borrowings	0	0	'	'	'	'	'	'	'
Line of Credit Facility, Current Borrowing Capacity	'	'	'	'	2,500	'	'	'	'
Proceeds from Issuance of Senior Long-term Debt	'	'	'	'	'	'	'	1,470	1,240
Repayments of Long-term Debt	$455	$9,439	$6,144	'	'	'	'	'	'

Debt_Obligations_Narrative_Sun

Debt Obligations Narrative - Sunoco Logistics Credit Facilities (Details) (USD $)	Sep. 30, 2013
In Millions, unless otherwise specified
Debt Instrument [Line Items]	'
Outstanding borrowings	$0
Sunoco Logistics Revolving Credit Facility, due August 2016 [Member]	'
Debt Instrument [Line Items]	'
Line of Credit Facility, Maximum Borrowing Capacity	350
Sunoco Logistics Revolving Credit Facility, due August 2014 [Member] [Member]	'
Debt Instrument [Line Items]	'
Line of Credit Facility, Maximum Borrowing Capacity	200
Sunoco Logistics Revolving Credit Facility, due August 2013 [Member]	'
Debt Instrument [Line Items]	'
Outstanding borrowings	0
Sunoco Logistics Revolving Credit Facility, due April 2015 [Member]	'
Debt Instrument [Line Items]	'
Line of Credit Facility, Current Borrowing Capacity	35
Outstanding borrowings	$35

Debt_Obligations_Narrative_Sou

Debt Obligations Narrative - Southern Union Credit Facility (Details) (USD $)	Sep. 30, 2013	Apr. 30, 2013
In Millions, unless otherwise specified		Southern Union Credit Facility [Member]
Line of Credit Facility [Line Items]	'	'
Amount Outstanding	$0	$240

Redeemable_Preferred_Units_Nar

Redeemable Preferred Units Narrative (Details) (USD $)	3 Months Ended	9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013	Sep. 02, 2029
Proceeds from Issuance of Preferred Stock and Preference Stock	$300	'	'
Preferred Stock Redemption Premium	'	40	'
Conversion of Stock, Shares Converted	'	2,459,017	'
Gain Recognized from Conversion of Series A Preferred Units	'	26	'
Preferred Units Redemption Amount	'	'	$35
ETE Preferred Units [Member]	'	'	'
Preferred Units, Outstanding	3,000,000	3,000,000	'
Regency Preferred Units [Member]	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	2,047,571	'

Equity_Narrative_Details

Equity Narrative (Details) (USD $)

9 Months Ended

3 Months Ended

0 Months Ended

9 Months Ended

9 Months Ended

In Millions, except Per Share data, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Aug. 07, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Goldman Sachs [Member]

ETE [Member]

ETP [Member]

Class H Units [Member]

Class H Units [Member]

Citrus Merger [Member]

Holdco Transaction [Member]

Equity Distribution Agreement entered in January 2013 [Member]

Equity Distribution Agreement entered in May 2013 [Member]

Equity distribution agreement [Member]

Distribution Reinvestment Plan [Member]

Distribution Reinvestment Plan [Member]

quarters

quarters

Equity Distribution Reinvestment Program, Capacity, Shares

'

'

'

'

2.7

'

'

'

'

'

'

'

'

Gain on Sale of Previously Unissued Stock by Subsidiary

($410)

$33

'

'

'

'

'

'

'

'

'

'

'

Equity Distribution Agreement, Capacity

'

'

'

'

'

'

'

'

'

200

800

'

'

Partners' Capital Account, Units, Sold in Public Offering

13.8

'

'

'

'

'

'

'

'

'

'

'

'

Share Price

$48.05

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from issuance of common units

657

'

13

'

'

'

'

'

'

'

'

568

76

Stock Issued During Period, Shares, New Issues

'

'

'

'

'

'

'

'

'

'

'

'

1.6

Partners' Capital Account, Units, Redeemed

'

'

'

'

'

50.2

'

'

'

'

'

'

'

Allocation of Profits, Losses and Other by Sunoco, Percent

'

'

'

'

'

50.05%

'

'

'

'

'

'

'

Distributions by Sunoco, IDRs and General Partner Interest

'

'

'

'

'

50.05%

'

'

'

'

'

'

'

Equity Distribution Agreement Commissions

6

'

'

'

'

'

'

'

'

'

'

'

'

Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount

426

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

16

12

'

'

'

'

Relinquishment of Rights of Incentive Distributions

'

'

'

'

'

'

'

220

210

'

'

'

'

Class H Incremental Cash Distributions

'

'

'

'

'

'

329

'

'

'

'

'

'

Incentive Distributions

'

'

'

$21

'

'

'

'

'

'

'

'

'

Equity_Table_Change_In_ETE_Com

Equity Table - Change In ETE Common Units (Details)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Partners' Capital Notes [Abstract]	'
Outstanding at December 31, 2012	280
Issuance of restricted units under equity incentive plans	0.8
Outstanding at September 30, 2013	280.8

Equity_Table_Quarterly_Distrib

Equity Table - Quarterly Distributions of Available Cash (Details) (USD $)

9 Months Ended

3 Months Ended

In Millions, except Per Share data, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Sunoco Logistics [Member]

Equity Distribution Agreement Commissions

$6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Record Date

'

4-Nov-13

5-Aug-13

6-May-13

7-Feb-13

4-Nov-13

5-Aug-13

6-May-13

7-Feb-13

4-Nov-13

5-Aug-13

6-May-13

7-Feb-13

8-Nov-13

8-Aug-13

9-May-13

8-Feb-13

Payment Date

'

19-Nov-13

19-Aug-13

17-May-13

19-Feb-13

14-Nov-13

14-Aug-13

15-May-13

14-Feb-13

14-Nov-13

14-Aug-13

13-May-13

14-Feb-13

14-Nov-13

14-Aug-13

15-May-13

14-Feb-13

Distributions paid, rate per unit

'

$0.67

$0.66

$0.65

$0.64

$0.91

$0.89

$0.89

$0.89

$0.47

$0.47

$0.46

$0.46

$0.63

$0.60

$0.57

$0.55

Equity_Table_IDR_Schedule_Deta

Equity Table - 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

Equity_Table_Accumulated_Other

Equity Table - Accumulated Other Comprehensive Income (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Partners' Capital Notes [Abstract]	'	'
Net gains (losses) on commodity related hedges	$0	($3)
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	-22
Amounts attributable to noncontrolling interest	-2	10
Accumulated other comprehensive income (loss)	$1	($12)

UnitBased_Compensation_Plans_N

Unit-Based Compensation Plans Narrative (Details) (USD $)	9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013
ETE Long-Term Incentive Plan [Member]	'
Remain unvested award	804,190
Unrecognized compensation expense	$39
Weighted average period for recognition, years	'4 years 3 months 0 days
ETE Long-Term Incentive Plan [Member] | Employee [Member]	'
Granted unvested awards	750,000
ETE Long-Term Incentive Plan [Member] | Director [Member]	'
Granted unvested awards	6,042
ETE Unit-Based Compensation Plans [Member]	'
Weighted average grant date fair value, per unit	$55.95
ETP Unit-Based Compensation Plans [Member]	'
Granted unvested awards	1,142,663
Weighted average grant date fair value, per unit	$45.74
Remain unvested award	2,840,725
Unrecognized compensation expense	72
Weighted average period for recognition, years	'1 year 9 months 0 days
ETP Unit-Based Compensation Plans [Member] | Director [Member]	'
Granted unvested awards	9,060
Regency Phantom Units [Member]	'
Vesting period (years)	'5 years 0 months 0 days
Weighted average grant date fair value per unit option	$23.41
Remain unvested award	1,168,247
Granted awards	52,360
Unrecognized compensation expense	20
Weighted average period for recognition, years	'3 years 6 months 0 days
Sunoco Logistics Unit-Based Compensation Plan [Member]	'
Remain unvested award	918,031
Unrecognized compensation expense	$16
Weighted average period for recognition, years	'2 years 5 months 0 days
Director [Member]	'
Vesting period (years)	'5 years 0 months 0 days
Minimum [Member] | Director [Member]	'
Vesting period (years)	'3 years 0 months 0 days
Maximum [Member] | Director [Member]	'
Vesting period (years)	'5 years 0 months 0 days

Income_Taxes_Table_Partnership

Income Taxes Table - Partnership's Income Tax Expense from Continuing Operations (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 Disclosure [Abstract]	'	'	'	'
Income tax expense from continuing operations	$49	$26	$136	$33
Effective Income Tax Rate, Continuing Operations	13.00%	19.00%	12.00%	3.00%

Retirement_Benefits_Narrative_

Retirement Benefits Narrative (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
Defined Benefit Plan, Curtailments	'	'	'		$75	'
Noncurrent refund liability	'	'	'		60	'
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	0	0	0		'	15
Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'		'	'
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	'	'	$0	[1]	$15	$15	[1],[2]
[1]	(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 wa
[2]	(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.

Retirement_Benefits_Table_Comp

Retirement Benefits Table - Components of Pension Expense (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
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'	'
Gain on curtailment of other postretirement benefit plans	$0		$0		$0		'	($15)
Pension Plans, Defined Benefit [Member]	'		'		'		'	'
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'	'
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]
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0		0	[1]	0		'	0	[1]
Gain on curtailment of other postretirement benefit plans	'		'		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]
Defined Benefit Plan, Amortization of Gains (Losses)	-1		0	[1]	-2		'	0	[1]
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	'		'		2		'	0	[1]
Other Postretirement Benefit Plans, Defined Benefit [Member]	'		'		'		'	'
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'	'
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]
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	1		0	[1]	1		'	0	[1]
Gain on curtailment of other postretirement benefit plans	'		'		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]
Defined Benefit Plan, Amortization of Gains (Losses)	0		0	[1]	0		'	0	[1]
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	'		'		$0		'	$0	[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 wa
[3]	a

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	Sep. 30, 2013	Jan. 12, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
						Regency 4.50% Senior Notes Due 2023 [Member]	AmeriGas [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, Face Amount	'	'	'	'	'	600,000,000	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	'	'	'	'	4.50%	'	'	'	'
Guarantor Obligations, Current Carrying Value	'	'	'	'	'	600,000,000	'	'	'	'
Lease Expiration Date	'	'	31-Dec-56	'	'	'	'	'	'	'
Operating Leases, Rent Expense	33,000,000	12,000,000	98,000,000	31,000,000	'	'	'	'	'	'
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
Site Contingency, Number Of Sites Needing Remediation	'	'	39	'	'	'	'	'	'	'
Payments for Environmental Liabilities	$9,000,000	'	$27,000,000	'	'	'	'	'	'	'

Regulatory_Matters_Commitments3

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Environmental Exit Cost [Line Items]	'	'
Current	$40	$46
Non-current	192	166
Total environmental liabilities	$232	$212

Price_Risk_Management_Assets_A2

Price Risk Management Assets And Liabilities Narrative (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	ETP [Member]	Regency [Member]	Price Risk Management Liabilities [Member]
Option Premiums	'	'	$7
Expected gains (losses) related to derivatives to be reclassified into earnings over next year related to amounts currently reported an AOCI	1	'	'
Notional Amount of Credit Risk Derivatives	'	7	'
Derivative, Fair Value, Amount Offset Against Collateral, Net	'	$2	'

Price_Risk_Management_Assets_A3

Price Risk Management Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details)	Sep. 30, 2013	Dec. 31, 2012
	MMbtu	MMbtu
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]	'	'
Notional Volume	-27,402,500	-30,980,000
Maximum Term Of Commodity Derivatives	'2017	'2014
Minimum Term Of Commodity Derivatives	'2013	'2013
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]	'	'
Notional Volume	1,690,000	'
Maximum Term Of Commodity Derivatives	'2016	'
Minimum Term Of Commodity Derivatives	'2013	'
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Future [Member] | ETP [Member]	'	'
Notional Volume	6,560,000	'
Maximum Term Of Commodity Derivatives	'2019	'
Minimum Term Of Commodity Derivatives	'2013	'
Trading [Member] | Mark-To-Market Derivatives [Member] | Crude Oil [Member] | Future [Member] | ETP [Member]	'	'
Notional Volume	80,000	'
Maximum Term Of Commodity Derivatives	'2013	'
Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | Call Option [Member] | ETP [Member]	'	'
Notional Volume	-1,700	1,656,400
Maximum Term Of Commodity Derivatives	'2013	'2013
Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | Forwards Swaps [Member] | ETP [Member]	'	'
Notional Volume	562,250	19,650
Maximum Term Of Commodity Derivatives	'2013	'2013
Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | Future [Member] | ETP [Member]	'	'
Notional Volume	97,212	-1,509,300
Maximum Term Of Commodity Derivatives	'2013	'2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | Future [Member] | ETP [Member]	'	'
Notional Volume	-93,327	-666,000
Maximum Term Of Commodity Derivatives	'2014	'2013
Minimum Term Of Commodity Derivatives	'2013	'
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]	'	'
Notional Volume	-5,300,000	150,000
Maximum Term Of Commodity Derivatives	'2014	'2013
Minimum Term Of Commodity Derivatives	'2013	'
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]	'	'
Notional Volume	6,965,000	-83,292,500
Maximum Term Of Commodity Derivatives	'2016	'2013
Minimum Term Of Commodity Derivatives	'2013	'
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]	'	'
Notional Volume	15,176,000	8,395,000
Maximum Term Of Commodity Derivatives	'2014	'2014
Minimum Term Of Commodity Derivatives	'2013	'2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Forward Physical Swaps [Member] | ETP [Member]	'	'
Notional Volume	-11,663,485	11,689,855
Maximum Term Of Commodity Derivatives	'2014	'2014
Minimum Term Of Commodity Derivatives	'2013	'2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Future [Member] | ETP [Member]	'	'
Notional Volume	-14,072,500	27,077,500
Maximum Term Of Commodity Derivatives	'2015	'2013
Minimum Term Of Commodity Derivatives	'2013	'
Non Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]	'	'
Notional Volume	-1,182,000	-30,000
Maximum Term Of Commodity Derivatives	'2014	'2013
Minimum Term Of Commodity Derivatives	'2013	'
Non Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | Forwards Swaps [Member] | Regency [Member]	'	'
Notional Volume	144,000	243,000
Maximum Term Of Commodity Derivatives	'2014	'2014
Minimum Term Of Commodity Derivatives	'2013	'2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]	'	'
Notional Volume	829,000	356,000
Maximum Term Of Commodity Derivatives	'2014	'2014
Minimum Term Of Commodity Derivatives	'2013	'
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards Swaps [Member] | Regency [Member]	'	'
Notional Volume	33,642,000	3,318,000
Maximum Term Of Commodity Derivatives	'2014	'2013
Minimum Term Of Commodity Derivatives	'2013	'
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]	'	'
Notional Volume	-6,577,500	-18,655,000
Maximum Term Of Commodity Derivatives	'2013	'2013
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Hedged Item - Inventory [Member] | ETP [Member]	'	'
Notional Volume	47,215,000	44,272,500
Maximum Term Of Commodity Derivatives	'2014	'2013
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Future [Member] | ETP [Member]	'	'
Notional Volume	-47,215,000	-44,272,500
Maximum Term Of Commodity Derivatives	'2014	'2013
Non Trading [Member] | Cash Flow Hedging [Member] | Refined Products [Member] | Future [Member] | ETP [Member]	'	'
Notional Volume	'	-98,000
Maximum Term Of Commodity Derivatives	'	'2013
Non Trading [Member] | Cash Flow Hedging [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]	'	'
Notional Volume	-1,150,000	'
Maximum Term Of Commodity Derivatives	'2013	'
Non Trading [Member] | Cash Flow Hedging [Member] | Natural Gas [Member] | Future [Member] | ETP [Member]	'	'
Notional Volume	-5,720,000	-8,212,500
Maximum Term Of Commodity Derivatives	'2013	'2013
Non Trading [Member] | Cash Flow Hedging [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]	'	'
Notional Volume	-720,000	-930,000
Maximum Term Of Commodity Derivatives	'2013	'2013
Non Trading [Member] | Cash Flow Hedging [Member] | Crude Oil [Member] | Future [Member] | ETP [Member]	'	'
Notional Volume	-120,000	'
Maximum Term Of Commodity Derivatives	'2013	'

Price_Risk_Management_Assets_A4

Price Risk Management Assets And Liabilities Table - Interest Rate Swaps Outstanding (Details) (Interest Rate Derivatives [Member], USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
March 2017 [Member] | Parent Company [Member]	'		'
Notional Amount	$0		$500
Type	'Pay a fixed rate of 1.25% and receive a floating rate	[1]	'
July 2013 [Member] | ETP [Member]	'		'
Notional Amount	0	[2]	400	[2]
Type	'Forward-starting to pay a fixed rate of 4.03% and receive a floating rate	[1]	'
July 2014 [Member] | ETP [Member]	'		'
Notional Amount	400	[2]	400	[2]
Type	'Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	[1]	'
July 2018 [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%	[1]	'
June 2021 [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%	[1]	'
November 2016 [Member] | Southern Union [Member]	'		'
Notional Amount	25		75
Type	'Pay a fixed rate of 2.97% and receive a floating rate		'
November 2021 [Member] | Southern Union [Member]	'		'
Notional Amount	450		450
Type	'Pay a fixed rate of 3.75% and receive a floating rate		'
February 2023 [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%	[1]	'
[1]	(1) Floating rates are based on 3-month LIBOR.
[2]	(2) Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.

Price_Risk_Management_Assets_A5

Price Risk Management Assets And Liabilities Table - Fair Value of Derivative Instruments (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Total derivatives assets	$210	$215
Total derivatives liabilities	-271	-439
Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	16	8
Total derivatives liabilities	-3	-10
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]	'	'
Total derivatives assets	16	8
Total derivatives liabilities	-3	-10
Not Designated as Hedging Instrument [Member]	'	'
Total derivatives assets	194	207
Total derivatives liabilities	-268	-429
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]	'	'
Total derivatives assets	112	110
Total derivatives liabilities	-95	-116
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]	'	'
Total derivatives assets	39	40
Total derivatives liabilities	-38	-44
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]	'	'
Total derivatives assets	43	55
Total derivatives liabilities	-112	-235
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]	'	'
Total derivatives assets	0	0
Total derivatives liabilities	-23	-25
Current Assets Held For Sale [Member] | Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]	'	'
Total derivatives assets	0	1
Total derivatives liabilities	0	0
Non-Current Assets Held For Sale [Member] | Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]	'	'
Total derivatives assets	0	1
Total derivatives liabilities	0	0
Current Liabilities Held For Sale [Member] | Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]	'	'
Total derivatives assets	0	0
Total derivatives liabilities	$0	($9)
Fair Value Hedging [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member] | Non Trading [Member] | Natural Gas [Member]	'	'
Derivative, Nonmonetary Notional Amount	-6,577,500	-18,655,000

Price_Risk_Management_Assets_A6

Price Risk Management Assets And Liabilities Table - Gross FV and Netting Offset (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	$210	$215
Derivative Liability, Fair Value, Gross Liability	-271	-439
Netting [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	207	177
Derivative Liability, Fair Value, Gross Liability	-197	-248
Derivative Asset, Fair Value, Gross Liability	-32	-25
Derivative Liability, Fair Value, Gross Asset	32	25
Derivative Asset, Fair Value, Net	160	152
Derivative Liability, Fair Value, Net	-131	-162
Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value	50	63
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value	-140	-277
Netting [Member] | Bi-lateral contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	37	28
Derivative Liability, Fair Value, Gross Liability	-38	-27
Netting [Member] | Broker cleared derivative contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	170	149
Derivative Liability, Fair Value, Gross Liability	-159	-221
Netting [Member] | Asset Fair Value, Netting Offset [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Collateral Paid To OTC Counterparties	0	0
Payments on Margin Deposits	-15	0
Netting [Member] | Liability Fair Value, Netting Offset [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Collateral Paid To OTC Counterparties	0	2
Payments on Margin Deposits	$34	$59

Price_Risk_Management_Assets_A7

Price Risk Management Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Recognized OCI on Derivatives (Details) (USD $)	3 Months Ended		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)	$6	$4	$31
Commodity Derivatives [Member]	'	'	'	'
Change in Value Recognized in OCI on Derivatives (Effective Portion)	-4	11	4	16
Interest Rate Derivatives [Member]	'	'	'	'
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$0	($5)	$0	$15

Price_Risk_Management_Assets_A8

Price Risk Management Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Amount of Gain (Loss) Recognized (Details) (USD $)	3 Months Ended		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	$25
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	0	10	4	29
Amount of Gain/(Loss) Recognized in Income on Derivatives	-18	-48	22	-56
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member]	'	'	'	'
Amount of Gain/(Loss) Recognized in Income on Derivatives	-11	4	-12	-7
Commodity Derivatives [Member] | Cost of Products Sold [Member]	'	'	'	'
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	3	9	5	25
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	0	10	4	29
Amount of Gain/(Loss) Recognized in Income on Derivatives	-34	-48	-20	-36
Commodity Derivatives [Member] | Deferred Gas Purchases [Member]	'	'	'	'
Amount of Gain/(Loss) Recognized in Income on Derivatives	0	0	-3	0
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member]	'	'	'	'
Amount of Gain/(Loss) Recognized in Income on Derivatives	3	-6	55	-23
Embedded Derivatives [Member] | Other Income (Expenses) [Member]	'	'	'	'
Amount of Gain/(Loss) Recognized in Income on Derivatives	$24	$2	$2	$10

Other_Information_Table_Other_

Other Information Table - 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	266	270
Total other current assets	$321	$311

Other_Information_Table_Accrue

Other Information Table - Accrued and Other Current Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Other Information [Abstract]	'	'
Interest payable	$346	$334
Customer advances and deposits	70	61
Accrued Capital Expenditures	288	427
Accrued wages and benefits	200	250
Taxes payable other than income taxes	294	208
Income taxes payable	82	41
Deferred income taxes	243	130
Deferred Revenue, Current	2	0
Other Accrued Liabilities, Current	397	303
Total accrued and other current liabilities	$1,922	$1,754

Reportable_Segments_Narrative_

Reportable Segments Narrative (Details) (Regency [Member], Lone Star L.L.C. [Member])	9 Months Ended
	Sep. 30, 2013
Regency [Member] | Lone Star L.L.C. [Member]	'
Segment Reporting Information [Line Items]	'
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	30.00%

Reportable_Segments_Table_Segm

Reportable Segments Table - Segment Adjusted EBITDA (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
Segment Reporting Information [Line Items]	'	'	'	'
Adjusted EBITDA	$1,049	$754	$3,264	$2,063
Depreciation and amortization	-332	-211	-962	-571
Interest Expense, net of interest capitalized	-298	-237	-913	-732
Bridge loan related fees	0	0	0	-62
Gain on deconsolidation of Propane Business	0	0	0	1,057
Gain on sale of AmeriGas common units	87	0	87	0
Gains (losses) on interest rate derivatives	3	-6	55	-23
Non-cash unit-based compensation expense	-16	-10	-43	-34
Unrealized Gain (Loss) on commodity risk management activities	22	4	45	-43
Losses on extinguishment of debt	0	0	-7	-123
Gain on curtailment of other postretirement benefit plans	0	0	0	15
LIFO valuation adjustment	6	0	22	0
Equity in earnings of unconsolidated affiliates	38	21	182	118
Adjusted EBITDA related to unconsolidated affiliates	-165	-148	-553	-429
Adjusted EBITDA related to discontinued operations	-12	-32	-75	-66
Other	10	-1	6	1
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	392	134	1,108	1,171
Investment In ETP [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Adjusted EBITDA	942	660	2,967	1,796
Investment In Regency [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Adjusted EBITDA	172	141	446	398
Corporate And Other [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Adjusted EBITDA	-9	-7	-38	-48
Adjustments And Eliminations [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Adjusted EBITDA	($56)	($40)	($111)	($83)

Reportable_Segments_Table_Segm1

Reportable Segments Table - Segment Assets (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Assets	$50,043	$48,904
Investment In ETP [Member]	'	'
Assets	43,556	43,230
Investment In Regency [Member]	'	'
Assets	8,566	8,123
Corporate And Other [Member]	'	'
Assets	779	707
Adjustments And Eliminations [Member]	'	'
Assets	($2,858)	($3,156)

Reportable_Segments_Table_Reve

Reportable Segments Table - Revenues (External and Intersegment) by Investments (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
Revenues	$12,486	$2,104	$35,728	$5,651
Investment In ETP [Member]	'	'	'	'
Revenue from External Customers	11,848	1,791	34,214	4,697
Intersegment Revenues	54	11	93	24
Segment Reporting Information, Revenue for Reportable Segment	11,902	1,802	34,307	4,721
Revenues	11,902	1,802	34,307	4,721
Investment In Regency [Member]	'	'	'	'
Revenue from External Customers	633	526	1,796	1,406
Intersegment Revenues	32	1	48	7
Segment Reporting Information, Revenue for Reportable Segment	665	527	1,844	1,413
Revenues	665	527	1,844	1,413
Adjustments And Eliminations [Member]	'	'	'	'
Revenue from External Customers	($81)	($225)	($423)	($483)

Reportable_Segments_Table_Reve1

Reportable Segments Table - Revenues from External Customers 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
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	$12,486	$2,104	$35,728	$5,651
Intrastate Transportation And Storage [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenue from External Customers	502	503	1,711	1,402
Interstate Transportation and Storage [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenue from External Customers	296	309	973	761
Midstream [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenue from External Customers	683	757	2,021	1,845
NGL Transportation And Services [Member] [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenue from External Customers	537	157	1,303	459
Sunoco Logistics [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenue from External Customers	4,502	0	12,215	0
Retail Marketing [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenue from External Customers	5,297	0	15,805	0
All Other Segments [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenue from External Customers	85	76	279	254
Gathering And Processing [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	603	475	1,671	1,262
Contract Services [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	58	47	159	137
Corporate And Others [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	4	5	14	14
Investment In ETP [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	11,902	1,802	34,307	4,721
Less: Intersegment revenues	54	11	93	24
Revenue from External Customers	11,848	1,791	34,214	4,697
Investment In Regency [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	665	527	1,844	1,413
Less: Intersegment revenues	32	1	48	7
Revenue from External Customers	$633	$526	$1,796	$1,406

Supplemental_Financial_Stateme2

Supplemental Financial Statement Information Table - Balance Sheets (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Cash and cash equivalents	$1,177	$372	$172	$126
Accounts receivable from related companies	51	71	'	'
Other current assets	321	311	'	'
Total current assets	6,887	5,597	'	'
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,087	4,737	'	'
INTANGIBLE ASSETS, net	2,195	2,291	'	'
GOODWILL	6,428	6,434	'	'
OTHER NON-CURRENT ASSETS, net	607	533	'	'
Total assets	50,043	48,904	'	'
Accounts payable	3,544	3,107	'	'
Accounts payable to related companies	11	15	'	'
Interest payable	346	334	'	'
Price risk management liabilities	69	115	'	'
Accrued and other current liabilities	1,922	1,754	'	'
Current maturities of long-term debt	298	613	'	'
Total current liabilities	6,047	5,845	'	'
LONG-TERM DEBT, less current maturities	22,011	21,440	'	'
PREFERRED UNITS OF SUBSIDIARY	32	73	'	'
OTHER NON-CURRENT LIABILITIES	893	995	'	'
COMMITMENTS AND CONTINGENCIES	'	'	'	'
General Partner	-2	0	'	'
Limited Partners	1,401	2,125	'	'
Accumulated other comprehensive income (loss)	1	-12	'	'
Total partners’ capital	1,400	2,113	'	'
Total liabilities and equity	50,043	48,904	'	'
Parent Company [Member]	'	'	'	'
Cash and cash equivalents	100	9	18	18
Accounts receivable from related companies	7	11	'	'
Other current assets	1	3	'	'
Total current assets	108	23	'	'
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,003	6,094	'	'
INTANGIBLE ASSETS, net	15	19	'	'
GOODWILL	9	9	'	'
Notes Receivable From Affiliate	0	166	'	'
OTHER NON-CURRENT ASSETS, net	50	56	'	'
Total assets	4,185	6,367	'	'
Accounts payable	8	1	'	'
Accounts payable to related companies	27	15	'	'
Interest payable	62	48	'	'
Price risk management liabilities	0	5	'	'
Accrued and other current liabilities	0	1	'	'
Current maturities of long-term debt	4	4	'	'
Total current liabilities	101	74	'	'
LONG-TERM DEBT, less current maturities	2,683	3,840	'	'
PREFERRED UNITS OF SUBSIDIARY	0	331	'	'
OTHER NON-CURRENT LIABILITIES	1	9	'	'
COMMITMENTS AND CONTINGENCIES	'	'	'	'
General Partner	-2	0	'	'
Limited Partners	1,401	2,125	'	'
Accumulated other comprehensive income (loss)	1	-12	'	'
Total partners’ capital	1,400	2,113	'	'
Total liabilities and equity	$4,185	$6,367	'	'

Supplemental_Financial_Stateme3

Supplemental Financial Statement Information Schedule of Statements of Operations (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
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	($158)	($98)	($499)	($353)
Interest expense	-298	-237	-913	-732
Equity in earnings of unconsolidated affiliates	38	21	182	118
Losses on interest rate derivatives	3	-6	55	-23
Other, net	33	-3	0	28
Income tax expense (benefit)	49	26	136	33
NET INCOME ATTRIBUTABLE TO PARTNERS	151	35	368	255
GENERAL PARTNER’S INTEREST IN NET INCOME	1	0	1	1
LIMITED PARTNERS' INTEREST IN NET INCOME	150	35	367	254
Parent Company [Member]	'	'	'	'
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	-11	-7	-40	-48
Interest expense	-47	-64	-164	-170
Bridge loan related fees	0	0	0	-62
Equity in earnings of unconsolidated affiliates	207	118	573	552
Losses on interest rate derivatives	3	-6	9	-15
Other, net	-1	-6	-11	-2
INCOME BEFORE INCOME TAXES	151	35	367	255
Income tax expense (benefit)	0	0	-1	0
NET INCOME ATTRIBUTABLE TO PARTNERS	151	35	368	255
GENERAL PARTNER’S INTEREST IN NET INCOME	1	0	1	1
LIMITED PARTNERS' INTEREST IN NET INCOME	$150	$35	$367	$254

Supplemental_Financial_Stateme4

Supplemental Financial Statement Information Schedule Of Statements of Cash Flows (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$1,847	$897
Proceeds received in (paid for) acquisitions and other transactions, net	-5	-10
Net cash provided by (used in) investing activities	-833	-3,613
Proceeds from borrowings	9,768	9,081
Repayments of long-term debt	-9,439	-6,144
Distributions to partners	-544	-491
Redemption of Preferred Units	340	0
Debt issuance costs	-56	-99
Net cash provided by (used in) financing activities	-209	2,762
DECREASE IN CASH AND CASH EQUIVALENTS	805	46
CASH AND CASH EQUIVALENTS, beginning of period	372	126
CASH AND CASH EQUIVALENTS, end of period	1,177	172
Parent Company [Member]	'	'
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	650	406
Proceeds received in (paid for) acquisitions and other transactions, net	1,332	-1,113
Contributions to affiliate	-8	-445
Note receivable from affiliate	0	-221
Payments received on note receivable from affiliate	166	55
Net cash provided by (used in) investing activities	1,490	-1,724
Proceeds from borrowings	440	2,028
Repayments of long-term debt	-1,603	-141
Distributions to partners	-544	-491
Redemption of Preferred Units	-340	0
Debt issuance costs	-2	-78
Net cash provided by (used in) financing activities	-2,049	1,318
DECREASE IN CASH AND CASH EQUIVALENTS	91	0
CASH AND CASH EQUIVALENTS, beginning of period	9	18
CASH AND CASH EQUIVALENTS, end of period	$100	$18