Energy Transfer (ET) 8-K 14 Nov 13 2012 FY Management’s Discussion and Analysis of Financial Condition and Results of Operations Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2012	Feb. 21, 2013	Jun. 30, 2012
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	'8-K	'	'
Document Period End Date	31-Dec-12	'	'
Document Fiscal Year Focus	'2012	'	'
Document Fiscal Period Focus	'FY	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	279,961,650	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$8.60

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
ASSETS	'	'
Cash and cash equivalents	$372	$126
Accounts receivable, net of allowance for doubtful accounts of $2 and $9 as of December 31, 2012 and 2011, respectively	3,057	680
Accounts receivable from related companies	71	100
Inventories	1,522	328
Exchanges receivable	55	21
Price risk management assets	25	16
Current assets held for sale	184	0
Other current assets	311	184
Total current assets	5,597	1,455
PROPERTY, PLANT AND EQUIPMENT	30,388	16,530
ACCUMULATED DEPRECIATION	-2,104	-1,971
PROPERTY, PLANT AND EQUIPMENT, net	28,284	14,559
NON-CURRENT ASSETS HELD FOR SALE	985	0
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,737	1,497
NON-CURRENT RISK MANAGEMENT ASSETS	43	26
GOODWILL	6,434	2,039
INTANGIBLE ASSETS, net	2,291	1,072
OTHER NON-CURRENT ASSETS, net	533	249
Total assets	48,904	20,897
LIABILITIES AND EQUITY	'	'
Accounts payable	3,107	512
Accounts payable to related companies	15	33
Exchanges payable	156	18
Price risk management liabilities	115	90
Accrued and other current liabilities	1,754	764
Current maturities of long-term debt	613	424
Current liabilities held for sale	85	0
Total current liabilities	5,845	1,841
Liabilities of Disposal Group, Including Discontinued Operation, Noncurrent	142	0
LONG-TERM DEBT, less current maturities	21,440	10,947
DEFERRED INCOME TAXES	3,566	217
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	162	81
PREFERRED UNITS (Note 7)	331	323
OTHER NON-CURRENT LIABILITIES	995	29
COMMITMENTS AND CONTINGENCIES (Note 10)	'	'
Temporary Equity, Carrying Amount, Including Portion Attributable to Noncontrolling Interests	73	71
Partners' Capital	'	'
General Partner	0	0
Limited Partners:	'	'
Common Unitholders (279,955,608 and 222,972,708 units authorized, issued and outstanding as of December 31, 2012 and 2011, respectively)	2,125	52
Accumulated other comprehensive income (loss)	-12	1
Total partners’ capital	2,113	53
Noncontrolling interest	14,237	7,335
Total equity	16,350	7,388
Total liabilities and equity	$48,904	$20,897

Consolidated_Balance_Sheets_Ba

Consolidated Balance Sheets Balance Sheet (Paranthetical) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, except Share data, unless otherwise specified
Paranthetical [Abstract]	'	'
Allowance for doubtful accounts	$2	$9
Authorized	279,955,608	222,972,708
Issued	279,955,608	222,972,708
Outstanding	279,955,608	222,972,708

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
REVENUES:	'	'	'
Natural gas sales	$2,705	$2,982	$2,730
NGL sales	2,253	1,716	826
Crude sales	2,872	0	0
Gathering, transportation and other fees	2,386	1,819	1,360
Refined product sales	5,299	0	0
Other	1,449	1,673	1,640
Total revenues	16,964	8,190	6,556
COSTS AND EXPENSES:	'	'	'
Cost of products sold	13,088	5,169	4,102
Operating expenses	1,065	906	771
Depreciation and amortization	871	586	406
Selling, general and administrative	580	292	233
Total costs and expenses	15,604	6,953	5,512
OPERATING INCOME	1,360	1,237	1,044
OTHER INCOME (EXPENSE):	'	'	'
Interest expense, net of interest capitalized	-1,018	-740	-625
Bridge loan related fees	-62	0	0
Equity in earnings of unconsolidated affiliates	212	117	65
Gain on deconsolidation of Propane Business	1,057	0	0
Losses on extinguishments of debt	-123	0	-16
Losses on disposal of assets	4	1	5
Losses on non-hedged interest rate derivatives	-19	-78	-52
Impairments of investments in affiliates	0	-5	-53
Other, net	30	17	-4
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	1,437	548	359
Income tax expense from continuing operations	54	17	14
INCOME FROM CONTINUING OPERATIONS	1,383	531	345
Loss from discontinued operations	-109	-3	-8
NET INCOME	1,274	528	337
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	970	218	144
NET INCOME ATTRIBUTABLE TO PARTNERS	304	310	193
GENERAL PARTNER’S INTEREST IN NET INCOME	2	1	1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$302	$309	$192
Basic	1.17	1.39	0.87
Diluted	1.17	1.38	0.87
Basic	1.13	1.39	0.86
Diluted	1.13	1.38	0.86

Consolidated_Statements_Of_Com

Consolidated Statements Of Comprehensive Income (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement of Other Comprehensive Income [Abstract]	'	'	'
Net income	$1,274	$528	$337
Other comprehensive income, net of tax:	'	'	'
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	-17	-19	49
Change in value of derivative instruments accounted for as cash flow hedges	12	7	19
Change in value of available-for-sale securities	0	-1	-4
Change in other comprehensive income from equity investments	-9	0	0
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, Net of Tax	-10	0	0
Other comprehensive income (loss), net of tax, total	-24	-13	64
Comprehensive income	1,250	515	401
Less: Comprehensive income attributable to noncontrolling interest	959	209	150
Comprehensive income attributable to partners	$291	$306	$251

Consolidated_Statement_Of_Equi

Consolidated Statement Of Equity (USD $)	Total	General Partner [Member]	Common Unitholders [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
In Millions, unless otherwise specified
Balance at Dec. 31, 2009	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Regency Transactions (See Note 3)	$2,105	$1	$209	$0	$1,895
Distributions to partners	-483	-1	-482	0	0
Distributions to noncontrolling interest	568	0	0	0	568
Units issued in Southern Union Merger (See Note 3)	0	'	'	'	'
Subsidiary units issued for cash	1,552	0	142	0	1,410
Non-cash compensation expense, net of units tendered by employees for tax withholdings	26	0	1	0	25
Capital contributions from noncontrolling interest	0	'	'	'	'
Other, net	-6	0	-1	0	-5
Other comprehensive loss, net of tax	64	0	0	58	6
Net income	337	1	192	0	144
Balance at Dec. 31, 2010	6,247	1	114	5	6,127
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Regency Transactions (See Note 3)	-526	-2	-524	0	0
Distributions to partners	-779	0	0	0	-779
Distributions to noncontrolling interest	-1,903	0	-153	0	-1,750
Units issued in Southern Union Merger (See Note 3)	0	'	'	'	'
Subsidiary units issued for cash	3	0	0	0	3
Non-cash compensation expense, net of units tendered by employees for tax withholdings	34	0	1	0	33
Capital contributions from noncontrolling interest	0	'	'	'	'
Other, net	-9	0	-1	0	-8
Other comprehensive loss, net of tax	-13	0	0	-4	-9
Net income	528	1	309	0	218
Balance at Dec. 31, 2011	7,388	0	52	1	7,335
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Distributions to partners	-666	-2	-664	0	0
Distributions to noncontrolling interest	1,017	0	0	0	1,017
Units issued in Southern Union Merger (See Note 3)	2,354	0	2,354	0	0
Subsidiary units issued for cash	1,103	0	33	0	1,070
Non-cash compensation expense, net of units tendered by employees for tax withholdings	32	0	1	0	31
Capital contributions from noncontrolling interest	42	0	0	0	42
Holdco Transaction	3,580	0	0	0	3,580
Subsidiary units issued in acquisitions	2,295	0	47	0	2,248
Other, net	-11	0	0	0	-11
Other comprehensive loss, net of tax	-24	0	0	-13	-11
Net income	1,274	2	302	0	970
Balance at Dec. 31, 2012	$16,350	$0	$2,125	($12)	$14,237

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'	'
Net income	$1,274,000,000	$528,000,000	$337,000,000
Reconciliation of net income to net cash provided by operating activities:	'	'	'
Impairments of investments in affiliates	0	5,000,000	53,000,000
Payment for termination of Parent Company interest rate derivatives	0	0	-169,000,000
Proceeds from termination of ETP interest rate derivatives	0	0	26,000,000
Depreciation and amortization	871,000,000	586,000,000	406,000,000
Deferred income taxes	51,000,000	1,000,000	4,000,000
Gain on curtailment of other postretirement benefit plans	-15,000,000	0	0
Amortization of finance costs charged to interest	-13,000,000	20,000,000	18,000,000
Bridge loan related fees	62,000,000	0	0
Non-cash compensation expense	47,000,000	42,000,000	31,000,000
Gain on deconsolidation of Propane Business	-1,057,000,000	0	0
Losses on extinguishments of debt	123,000,000	0	16,000,000
Losses on disposal of assets	4,000,000	1,000,000	5,000,000
Equity in earnings of unconsolidated affiliates	-212,000,000	-117,000,000	-65,000,000
Distributions from unconsolidated affiliates	208,000,000	126,000,000	149,000,000
Inventory, LIFO Reserve, Effect on Income, Net	75,000,000	0	0
Other non-cash	211,000,000	28,000,000	17,000,000
Net change in operating assets and liabilities, net of effects of acquisitions, dispositions and deconsolidation (see Note 2)	-551,000,000	158,000,000	260,000,000
Net cash provided by operating activities	1,078,000,000	1,378,000,000	1,088,000,000
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Cash received from (paid) all other acquisitions	-10,000,000	-1,972,000,000	-345,000,000
Capital expenditures (excluding allowance for equity funds used during construction)	-3,271,000,000	-1,810,000,000	-1,510,000,000
Contributions in aid of construction costs	35,000,000	25,000,000	14,000,000
Contributions to unconsolidated affiliates	-37,000,000	-222,000,000	-93,000,000
Distributions from unconsolidated affiliates in excess of cumulative earnings	189,000,000	72,000,000	0
Proceeds from Divestiture of Businesses	207,000,000	0	0
Cash proceeds from contribution of propane operations	44,000,000	33,000,000	104,000,000
Cash proceeds from contribution of propane operations	1,443,000,000	0	0
Other	176,000,000	0	0
Net cash used in investing activities	-4,196,000,000	-3,874,000,000	-1,830,000,000
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Proceeds from borrowings	12,870,000,000	8,262,000,000	4,389,000,000
Repayments of long-term debt	-8,848,000,000	-6,264,000,000	-4,078,000,000
Subsidiary equity offerings, net of issue costs	1,103,000,000	1,903,000,000	1,552,000,000
Distributions to partners	-666,000,000	-526,000,000	-483,000,000
Distributions to noncontrolling interests	-1,017,000,000	-779,000,000	-568,000,000
Debt issuance costs	-112,000,000	-53,000,000	-49,000,000
Capital contributions from noncontrolling interest	42,000,000	0	0
Other, net	-8,000,000	-7,000,000	-3,000,000
Net cash provided by financing activities	3,364,000,000	2,536,000,000	760,000,000
INCREASE IN CASH AND CASH EQUIVALENTS	246,000,000	40,000,000	18,000,000
CASH AND CASH EQUIVALENTS, beginning of period	126,000,000	86,000,000	'
CASH AND CASH EQUIVALENTS, end of period	372,000,000	126,000,000	86,000,000
SUG Merger [Member]	'	'	'
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Cash received from (paid) all other acquisitions	($2,972,000,000)	$0	$0

Operations_And_Organization

Operations And Organization	12 Months Ended
	Dec. 31, 2012
Operations And Organization [Abstract]	'
Operations And Organization	'
	OPERATIONS AND ORGANIZATION:
	Financial Statement Presentation
	The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2012, 2011 and 2010, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. Management has evaluated subsequent events through the date the financial statements were issued.
	We obtained control of Regency on May 26, 2010 as a result of the Regency Transactions. On March 26, 2012, we acquired all of the outstanding shares of Southern Union for approximately $3.01 billion in cash and approximately 57 million ETE Common Units. On October 5, 2012, ETP completed the Sunoco Merger and we and ETP also completed the Holdco Transaction at that time. See Note 3 for more information regarding the Regency Transactions, the Southern Union Merger, Sunoco Merger and Holdco Transaction.
	At December 31, 2012, our equity interests in Regency and ETP consisted of:
		General Partner		Incentive		Limited
		Interest (as a %		Distribution		Partner Units
		of total		Rights
		partnership		(“IDRs”)
		interest)
	ETP	0.9	%	100	%	50,226,967
	Regency	1.6	%	100	%	26,266,791
	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”);
	•	Holdco, in which we own a 60% interest and ETP owns the remaining 40%, which includes the operations of Southern Union and Sunoco; 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.
	As a result of the Regency Transactions in May 2010, the Southern Union Merger in March 2012 and the Sunoco Merger in October 2012, the periods presented herein do not include activities from Regency, Southern Union or Sunoco prior to the consummation of the respective mergers and/or transactions.
	Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.
	Certain prior period amounts have been reclassified to conform to the 2012 presentation. In October 2012, we sold Canyon for approximately $207 million.  The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been adjusted to present Canyon’s operations as discontinued operations. Canyon was previously included in our midstream operations. In December 2012, Southern Union entered into a purchase and sale agreement pursuant to which subsidiaries of Laclede Gas Company, Inc. have agreed to acquire the assets of Southern Union’s Missouri Gas Energy and New England Gas Company divisions. For the period from March 26, 2012 to December 31, 2012 the results of operations of distribution operations have been reclassified to income from discontinued operations. The assets and liabilities of the disposal group have been reclassified and reported as assets and liabilities held for sale as of December 31, 2012.
	Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, Southern Union, Sunoco, Sunoco Logistics and Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
	Business Operations
	The Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. Effective with the acquisition of Southern Union in March 2012, the Parent Company also generated cash flows through its wholly-owned subsidiary, Southern Union until its contribution of Southern Union to Holdco on October 5, 2012. Subsequent to October 5, 2012, we also generate cash flows from our direct investment in Holdco. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein.
	Our activities are primarily conducted through our operating subsidiaries as follows:
	•	ETP’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. Our 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. Our midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.
	•	ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:
	•	Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
	•	ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.
	•	ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.
	•	CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus Corp., 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 is 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 is a Delaware limited liability company that is owned 40% and 60% by ETP and ETE, respectively. Holdco directly owns Southern Union and Sunoco. Pursuant to a stockholders agreement between ETE and ETP, ETP controls Holdco. As such, ETP consolidates Holdco (including Sunoco and Southern Union) in its financial statements which their 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 gathering, processing, transportation, storage and distribution of natural gas in the United States.
	◦	Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail and operates convenience stores in 25 states, 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, contract 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 Haynesville, Eagle Ford, Barnett, Fayetteville, Bone Spring, Avalon and Marcellus shales, as well as the Permian Delaware basin and the mid-continent region. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.
	As discussed in Note 15 to our consolidated financial statement, subsequent to the Holdco Acquisition on April 30, 2013, our reportable segments changed and currently reflect the following reportable business segments: Investment in ETP; Investment in Regency; and Corporate and Other.

Estimates_Significant_Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detail	12 Months Ended
	Dec. 31, 2012
Accounting Policies [Abstract]	'
Estimates, Significant Accounting Policies and Balance Sheet Detail	'
	ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
	Certain of our significant accounting policies have been impacted by current year transactions. See Note 3 for a discussion of these transactions.
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
	The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
	Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.
	Revenue Recognition
	Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.
	Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
	Our intrastate transportation and storage and interstate transportation and storage operations’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
	Our intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from the midstream operations’ marketing activities, and from producers at the wellhead.
	In addition, our intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
	Results from the midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
	We also utilize other types of arrangements in our midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we 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, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
	NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer.
	We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
	Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
	Our retail marketing operations sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. In addition some of Sunoco’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
	Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas gathering, processing and transportation, (iii) contract compression services and (iv) contract treating services. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas at a price approximating the index price and NGLs to third parties. Regency generally reports revenue gross when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers.
	Regulatory Accounting - Regulatory Assets and Liabilities
	Our interstate transportation and storage operations are subject to regulation by certain state and federal authorities and has accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
	Southern Union records regulatory assets with respect to its distribution operations.  We recorded regulatory assets with respect to Southern Union’s distribution operations, which have been classified as discontinued operations as of December 31, 2012. At December 31, 2012, we had $123 million of regulatory assets included in the consolidated balance sheet as non-current assets held for sale. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
	Cash, Cash Equivalents and Supplemental Cash Flow Information
	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 which are subject to an insignificant risk of changes in value.
	We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
	The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:
		Years Ended December 31,
		2012				2011			2010
	Accounts receivable	$	267			$	6		$	92
	Accounts receivable from related companies	(9		)		(24		)	(26		)
	Inventories	(258		)		51			15
	Exchanges receivable	14				1			1
	Other current assets	597				(51		)	33
	Other non-current assets, net	(129		)		7			6
	Accounts payable	(989		)		21			(67		)
	Accounts payable to related companies	92				6			(10		)
	Exchanges payable	—				2			(4		)
	Accrued and other current liabilities	(159		)		84			74
	Other non-current liabilities	26				—			—
	Price risk management assets and liabilities, net	(3		)		55			146
	Net change in operating assets and liabilities, net of effects of acquisitions, dispositions and deconsolidation	$	(551	)		$	158		$	260
	Non-cash investing and financing activities and supplemental cash flow information were as follows:
		Years Ended December 31,
		2012				2011			2010
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	420			$	226		$	108
	Net gain from subsidiary common unit transactions	$	80			$	153		$	352
	AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	1,123			$	—		$	—
	NON-CASH FINANCING ACTIVITIES:
	Issuance of common units in connection with Southern Union Merger (see Note 3)	$	2,354			$	—		$	—
	Long-term debt assumed and non-compete agreement notes payable issued from acquisitions	$	6,658			$	4		$	1,243
	Subsidiary issuance of Common Units in connection with certain acquisitions	$	2,295			$	3		$	584
	SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest, net of interest capitalized	$	997			$	728		$	547
	Cash paid for income taxes	$	23			$	27		$	9
	Accounts Receivable
	Our subsidiaries assess the credit risk of their customers. Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral). Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and specific identification.
	Inventories
	Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.
	Inventories consisted of the following:
		December 31,
		2012				2011
	Natural gas and NGLs, excluding propane	$	338			$	146
Propane	—				87
Crude oil	418				—
Refined products	572				—
Appliances, parts and fittings and other	194				95
Total inventories	$	1,522			$	328
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 designated hedged inventory is recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.
Exchanges
Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.
Other Current Assets
Other current assets consisted of the following:
	December 31,
	2012				2011
Deposits paid to vendors	$	41			$	66
Prepaid and other	270				118
Total other current assets	$	311			$	184
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
We and our subsidiaries review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $128 million during the year ended December 31, 2012.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an AFUDC is accrued. Interest is capitalized based on the current borrowing rate when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts - borrowed funds and equity funds.
Components and useful lives of property, plant and equipment were as follows:
	December 31,
	2012				2011
Land and improvements	$	553			$	137
Buildings and improvements (5 to 40 years)	587				279
Pipelines and equipment (5 to 83 years)	19,505				11,359
Natural gas and NGL storage facilities (5 to 46 years)	1,057				790
Bulk storage, equipment and facilities (5 to 83 years)	1,745				977
Tanks and other equipment (10 to 40 years)	1,194				644
Retail equipment (3 to 99 years)	258				—
Vehicles (3 to 25 years)	96				231
Right of way (20 to 83 years)	2,134				793
Furniture and fixtures (3 to 12 years)	50				48
Linepack	118				59
Pad gas	58				58
Other (2 to 19 years)	1,060				234
Construction work-in-process	1,973				921
	30,388				16,530
Less - Accumulated depreciation	(2,104		)		(1,971		)
Property, plant and equipment, net	$	28,284			$	14,559
We recognized the following amounts of depreciation expense and capitalized interest expense for the periods presented:
	Years Ended December 31,
	2012				2011			2010
Depreciation expense (1)	$	801			$	531		$	370
Capitalized interest, excluding AFUDC	$	99			$	13		$	4
(1)	Depreciation expense amounts have been adjusted by $26 million and $25 million for the years ended December 31, 2011 and 2010, respectively, to present Canyon’s operations as discontinued operations.
Advances to and Investments in Affiliates
Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment in which we have a 20% to 50% ownership and exercise significant influence over, but do not control the investee’s operating and financial policies.
See Note 4 for a discussion of these joint ventures.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage and midstream operations, as of November 30 for the Southern Union reporting units and as of December 31 for all others, including all of Regency’s reporting units. No goodwill impairments were recorded for the periods presented in these consolidated financial statements.
Changes in the carrying amount of goodwill were as follows:
	Balance, December 31, 2010				Goodwill acquired			Balance, December 31, 2011			Goodwill acquired			Disposal of Goodwill (1)			Balance, December 31, 2012
ETP Intrastate Transportation and Storage	$	10			$	—		$	10		$	—		—			$	10
ETP Interstate Transportation and Storage	99				—			99			1,785			—			1,884
ETP Midstream	50				—			50			338			—			388
ETP NGL Transportation and Services	—				432			432			—			—			432
ETP Retail Marketing	—				—			—			1,272			—			1,272
Investment in Sunoco Logistics	—				—			—			1,368			—			1,368
Investment in Regency	790				—			790			—			—			790
Corporate and Other	652				6			658			384			(752		)	290
Total	$	1,601			$	438		$	2,039		$	5,147		$	(752	)	$	6,434
(1) Includes goodwill deconsolidated or disposed of during the year ended December 31, 2012 and goodwill reclassified to non-current assets held for sale at December 31, 2012.
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. A net increase in goodwill of $4.40 billion was recorded during the year ended December 31, 2012, primarily due to $2.64 billion from the Sunoco Merger and $2.50 billion related to Southern Union, offset by $619 million in goodwill that was contributed as part of the deconsolidation of ETP’s Propane Business, and $133 million classified as assets held for sale. This additional goodwill is not expected to be deductible for tax purposes.
See further discussion regarding our acquisitions at Note 3.
Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our consolidated balance sheets the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows:
	December 31, 2012							December 31, 2011
	Gross Carrying				Accumulated			Gross Carrying			Accumulated
	Amount				Amortization			Amount			Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	2,032			$	(150	)	$	1,059		$	(135	)
Trade names (20 years)	66				(8		)	66			(5		)
Noncompete agreements (3 to 15 years)	—				—			15			(8		)
Patents (9 years)	48				(1		)	1			—
Other (10 to 15 years)	4				(1		)	1			(1		)
Total amortizable intangible assets	2,150				(160		)	1,142			(149		)
Non-amortizable intangible assets:
Trademarks	301				—			79			—
Total intangible assets	$	2,451			$	(160	)	$	1,221		$	(149	)
During 2012, in connection with the Southern Union Merger and Holdco Transaction, we recorded customer contracts of $1.07 billion with useful lives ranging from 5 to 20 years, patents of $48 million with useful lives of 10 years and non-amortizable trademarks of $301 million.
Aggregate amortization expense of intangibles assets was as follows:
	Years Ended December 31,
	2012				2011			2010
Reported in depreciation and amortization	$	70			$	55		$	36
Estimated aggregate amortization expense of intangible assets for the next five years was as follows:
Years Ending December 31:
2013	$	116
2014	115
2015	115
2016	115
2017	115
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
	December 31,
	2012				2011
Unamortized financing costs (3 to 30 years)	$	152			$	132
Regulatory assets	93				89
Deferred charges	140				—
Other	148				28
Total other non-current assets, net	$	533			$	249
Asset Retirement Obligation
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably determine the settlement dates.
Except for the AROs of Southern Union, Sunoco Logistics and Sunoco discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2012 and 2011 because the settlement dates were indeterminable. Although a number of other onshore assets in Southern Union’s system are subject to agreements or regulations that give rise to an ARO upon Southern Union’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco has legal asset retirement obligations for several other assets at its refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
Below is a schedule of AROs by entity recorded as other non-current liabilities in ETP’s consolidated balance sheet as of December 31, 2012:
Southern Union	$	46
Sunoco	53
Sunoco Logistics	41
	$	140
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have has in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
As of December 31, 2012, there were no legally restricted funds for the purpose of settling AROs.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
	December 31,
	2012				2011
Interest payable	$	334			$	204
Customer advances and deposits	61				101
Accrued capital expenditures	427				229
Accrued wages and benefits	250				80
Taxes payable other than income taxes	208				79
Income taxes payable	41				15
Deferred income taxes	130				—
Other	303				56
Total accrued and other current liabilities	$	1,754			$	764
Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
We have marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units and embedded derivatives in the Preferred Units of a Subsidiary (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 marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. 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. The fair value of the Preferred Units was based predominantly on an income approach model and is also considered Level 3.
Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of December 31, 2012 and 2011 was $24.15 billion and $12.21 billion, respectively. As of December 31, 2012 and 2011, the aggregate carrying amount of our consolidated debt obligations was $22.05 billion and $11.37 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 December 31, 2012 and 2011 based on inputs used to derive their fair values:
	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	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	(8		)		(1		)	(7		)	—
Total commodity derivatives	(168		)		(118		)	(50		)	—
Total Liabilities	$	(759	)		$	(118	)	$	(285	)	$	(356	)
	Fair Value Measurements at
	December 31, 2011 Using
	Fair Value				Level 1			Level 2			Level 3
	Total
Assets:
Marketable securities (included in other current assets)	$	1			$	1		$	—		$	—
Interest rate derivatives	36				—			36			—
Commodity derivatives:
Condensate — Forward Swaps	1				—			1			—
Natural Gas:
Basis Swaps IFERC/NYMEX	63				63			—			—
Swing Swaps IFERC	15				2			13			—
Fixed Swaps/Futures	219				215			4			—
Options — Puts	6				—			6			—
Forward Physical Swaps	1				—			1			—
Total commodity derivatives	305				280			25			—
Total Assets	$	342			$	281		$	61		$	—
Liabilities:
Interest rate derivatives	$	(117	)		$	—		$	(117	)	$	—
Series A Convertible Preferred Units	(323		)		—			—			(323		)
Embedded derivatives in the Regency Preferred Units	(39		)		—			—			(39		)
Commodity derivatives:
Condensate — Forward Swaps	(2		)		—			(2		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(82		)		(82		)	—			—
Swing Swaps IFERC	(16		)		(3		)	(13		)	—
Fixed Swaps/Futures	(148		)		(148		)	—			—
Forward Physical Swaps	(1		)		—			(1		)	—
NGLs — Forward Swaps	(9		)		—			(9		)	—
Propane — Forward Swaps	(4		)		—			(4		)	—
Total commodity derivatives	(262		)		(233		)	(29		)	—
Total Liabilities	$	(741	)		$	(233	)	$	(146	)	$	(362	)
The following table presents the material unobservable inputs used to estimate the fair value of the Preferred Units and the embedded derivatives in Regency’s Preferred Units:
	Unobservable Input		31-Dec-12
Preferred Units	Assumed Yield		6.11	%
Embedded derivatives in the Regency Preferred Units	Credit Spread		6.49	%
	Volatility		21.38	%
Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in Regency’s cost of equity and U. S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the Regency Preferred Units. Changes in Regency’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.
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 year ended December 31, 2012. There were no transfers between the fair value hierarchy levels during the years ended December 31, 2012 or 2011.
Balance, December 31, 2011	$	(362	)
Net unrealized gains included in other income (expense)	6
Balance, December 31, 2012	$	(356	)
Contributions in Aid of Construction Cost
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs
Shipping and handling costs related to fuel sold are included in cost of products sold. Shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and totaled $25 million, $40 million and $43 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Costs and Expenses
Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income.
Issuances of Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon ETP’s or Regency’s issuance of respective ETP or Regency Common Units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Taxes
ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2012, 2011 and 2010, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. Holdco, formed via the Holdco Transaction (see Note 3), which includes Sunoco and Southern Union, is included amongst these corporate subsidiaries. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
See Note 10 for income tax disclosures.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.
At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on non-hedged interest rate derivatives” in the consolidated statements of operations. See Note 12 for additional information related to interest rate derivatives.
Pensions and Other Postretirement Benefit Plans
Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.   Employers must recognize the change in the funded status of the plan in the year in which the change occurs through AOCI in stockholders’ equity.
See Note 13 for additional related information.
Allocation of Income
For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see Note 8).

Acquisitions_and_Related_Trans

Acquisitions and Related Transactions	12 Months Ended
	Dec. 31, 2012
Acquisitions and Dispositions [Abstract]	'
Acquisitions and Related Transactions	'
	ACQUISITIONS AND RELATED TRANSACTIONS:
	2012 Transactions
	Southern Union Merger
	On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union is the surviving entity in the merger and operated as a wholly-owned subsidiary of ETE until our contribution to Holdco discussed below. The assets acquired as a result of this merger significantly expand our existing geographic footprint of natural gas pipeline and natural gas transportation capacity and into natural gas utilities distribution, and are complementary to the assets owned and operated by our other entities.
	Under the terms of the merger agreement, Southern Union stockholders received a total of 56,982,160 ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.
	Citrus Acquisition
	In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.25 million ETP Common Units. See Note 4 for more information regarding ETP’s equity method investment in Citrus.
	In connection with the Citrus Acquisition, we relinquished our rights to an aggregate $220 million of incentive distributions from ETP that we would otherwise be entitled to receive over 16 consecutive quarters following the closing of the merger.
	Pursuant to the merger agreement, we also granted ETP a right of first offer with respect to any disposition by us or SUGS, a subsidiary of Southern Union that owns and operates a natural gas gathering and processing system serving the Permian Basin in West Texas and New Mexico.
	Sunoco Merger
	On October 5, 2012, 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 a total of approximately $2.6 billion in cash.
	Sunoco generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco also owned a 2% general partner interest, 100% of the IDRs, and 32% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco’s interests in Sunoco Logistics were transferred to ETP.
	Sunoco Logistics is a publicly traded limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary pipeline, terminalling and crude oil acquisition and marketing assets. The refined products pipelines business consists of refined products pipelines located in the northeast, midwest and southwest United States, and equity interests in refined products pipelines. The crude oil pipeline business consists of crude oil pipelines located principally in Oklahoma and Texas. The terminal facilities business consists of refined products and crude oil terminal capacity at the Nederland Terminal on the Gulf Coast of Texas and capacity at the Eagle Point terminal on the banks of the Delaware River in New Jersey. The crude oil acquisition and marketing business, principally conducted in Oklahoma and Texas, involves the acquisition and marketing of crude oil and consists of crude oil transport trucks and crude oil truck unloading facilities.
	Prior to the Sunoco Merger, on September 8, 2012, Sunoco completed the exit from its Northeast refining operations by contributing the refining assets at its Philadelphia refinery and various commercial contracts to PES, a joint venture with The Carlyle Group. Sunoco also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook facility continued to support operations at the Philadelphia refinery prior to commencement of the PES joint venture. Under the terms of the joint venture agreement, The Carlyle Group contributed cash in exchange for a 67% controlling interest in PES. In exchange for contributing its Philadelphia refinery assets and various commercial contracts to the joint venture, Sunoco retained an approximately 30% non-operating noncontrolling interest. The fair value of Sunoco’s retained interest in PES, which was $75 million on the date on which the joint venture was formed, was determined based on the equity contributions of The Carlyle Group. Sunoco has indemnified PES for environmental liabilities related to the Philadelphia refinery that arose from the operation of such assets prior the formation of the joint venture. The Carlyle Group will oversee day-to-day operations of PES and the refinery. JPMorgan Chase will provide working capital financing to PES in the form of an asset-backed loan, supply crude oil and other feedstocks to the refinery at the time of processing and purchase certain blendstocks and all finished refined products as they are processed. Sunoco entered into a ten-year supply contract for gasoline and diesel produced at the refinery for its retail marketing business.
	Holdco Transaction
	Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Prior to the contribution of Sunoco to Holdco, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90,706,000 Class F Units representing limited partner interests in ETP. The ETP Class F Units are entitled to 35% of the quarterly cash distribution generated by ETP and its subsidiaries other than Holdco, subject to a maximum cash distribution of $3.75 per ETP Class F Unit per year, which is the current distribution level. Pursuant to a stockholders agreement between ETE and ETP, ETP controls Holdco. Consequently, ETP consolidated Holdco (including Sunoco and Southern Union) in its financial statements subsequent to consummation of the Holdco Transaction.
	Under the terms of the Holdco transaction agreement, ETE relinquished an aggregate of $210 million of incentive distributions over 12 consecutive quarters following the closing of the Holdco Transaction. The relinquishment applied to the distribution paid with respect to the quarter ended September 30, 2012.
	Summary of Assets Acquired and Liabilities Assumed
	We accounted for the Southern Union Merger and Sunoco Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet presented as of December 31, 2012 reflects the purchase price allocations. Management is continuing to validate certain assumptions made in connection with the purchase price allocation of Sunoco. Certain amounts included in the purchase price allocation as of December 31, 2012 for Southern Union have been changed from amounts reflected as of March 31, 2012 based on management’s review of the valuation.
	The following table summarizes the assets acquired and liabilities assumed recognized as of the respective acquisition dates:
				Sunoco (1)				Southern Union(2)
	Total current assets			$	7,312			$	556
	Property, plant and equipment			6,686				6,242
	Goodwill			2,641				2,497
	Intangible assets			1,361				55
	Investments in unconsolidated affiliates			240				2,023
	Note receivable			821				—
	Other assets			128				163
				19,189				11,536
	Current liabilities			4,424				1,348
	Long-term debt obligations, including current maturities			2,879				3,120
	Deferred income taxes			1,762				1,419
	Other non-current liabilities			769				284
	Noncontrolling interest			3,580				—
				13,414				6,171
	Total consideration			5,775				5,365
	Cash received			2,714				37
	Total consideration, net of cash received			$	3,061			$	5,328
	(1) Includes amounts recorded with respect to Sunoco Logistics.
	(2) Includes ETP’s acquisition of Citrus.
	As a result of the Southern Union Merger, we recognized $38 million of merger-related costs during the year ended December 31, 2012. Southern Union’s revenue included in our consolidated statement of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statement of operations was approximately $39 million since the acquisition date to December 31, 2012.
	ETP incurred merger related costs related to the Sunoco Merger of $28 million during the year ended December 31, 2012. Sunoco’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco’s net loss included in our consolidated statement of operations was approximately $14 million during October through December 2012. Sunoco Logistics’ revenue included in our consolidated statement of operations was approximately $3.11 billion during October through December 2012. Sunoco Logistics’ net income included in our consolidated statement of operations was approximately $145 million during October through December 2012.
	Propane Operations
	On January 12, 2012, ETP contributed its propane operations, consisting of HOLP and Titan to AmeriGas. ETP received approximately $1.46 billion in cash and approximately 30 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, ETP entered into a support agreement with AmeriGas pursuant to which ETP is obligated to provide contingent, residual support of $1.5 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.5 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.
	We have not reflected the Propane operations as discontinued operations as ETP has a continuing involvement in this business as a result of the investment in AmeriGas that was transferred to ETP as consideration for the transaction.
	Discontinued Operations
	In October 2012, ETP sold Canyon for approximately $207 million.  The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been adjusted to present Canyon’s operations as discontinued operations. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $132 million during the year ended December 31, 2012.  Canyon was previously included in the midstream operations in the Investment in ETP segment.
	In December 2012, Southern Union entered into a purchase and sale agreement with the Laclede Entities, pursuant to which Laclede Missouri has agreed to acquire the assets of Missouri Gas Energy division and Laclede Massachusetts has agreed to acquire the assets of the New England Gas Company division. Total consideration is expected to be $1.04 billion, subject to customary closing adjustments, less the assumption of approximately $19 million of debt. For the period from March 26, 2012 to December 31, 2012 the results of continuing operations of distribution operations have been reclassified to income from discontinued operations. The assets and liabilities of the disposal group have been reclassified and reported as assets and liabilities held for sale as of December 31, 2012.
	Below is selected financial information related to Southern Union’s distribution operations for the period from March 26, 2012 to December 31, 2012:
	Revenue from discontinued operations	$	324
	Net loss of discontinued operations, excluding effect of taxes and overhead allocations	43
	The goodwill allocated to the disposal group was $133 million at December 31, 2012.
	SUGS Contribution
	On February 27, 2013, Southern Union entered into a definitive contribution agreement to contribute to Regency all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration to be paid by Regency in connection with this transaction will consist of (i) the issuance of 31,372,419 Regency common units to Southern Union, (ii) the issuance of 6,274,483 Regency Class F units to Southern Union, (iii) the distribution of $570 million in cash to Southern Union, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The Regency Class F units will 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. Upon the closing of the transaction, we will agree to forego all distributions with respect to our IDRs on the Regency common units issued in the transaction for the first eight consecutive quarters following the closing. The transaction is expected to close in the second quarter of 2013.
	2011 Transactions
	LDH Acquisition
	On May 2, 2011, ETP-Regency Midstream Holdings, LLC (“ETP-Regency LLC”), a joint venture owned 70% by ETP and 30% by Regency, acquired all of the membership interest in LDH Energy Asset Holdings LLC (“LDH”), from Louis Dreyfus Highbridge Energy LLC (“Louis Dreyfus”) for approximately $1.98 billion in cash (the “LDH Acquisition”), including working capital adjustments. ETP contributed approximately $1.38 billion to ETP-Regency LLC to fund its 70% share of the purchase price, while Regency contributed approximately $593 million to fund its 30% share of the purchase price. Subsequent to closing, ETP-Regency LLC was renamed Lone Star.
	Lone Star owns and operates a natural gas liquids storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in West Texas, passes through the Barnett Shale production area in North Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana. The acquisition of LDH by Lone Star expands ETP and Regency’s asset portfolios by adding a NGL platform with storage, transportation and fractionation capabilities.
	ETP accounted for the LDH Acquisition using the acquisition method of accounting. Lone Star’s results of operations are consolidated into our Investment in ETP segment, while Lone Star’s results are recorded as an equity method investment in our Investment in Regency reporting segment. Regency’s equity method investment in Lone Star is reflected by ETP as noncontrolling interest attributable to Lone Star. These amounts have been eliminated in our consolidated financial statements.
	2010 Transactions
	Regency Transactions
	On May 26, 2010, we acquired our equity interests in Regency in a series of transactions, which we refer to as the Regency Transactions. In the Regency Transactions, we:
	•	acquired the general partner interest and IDRs in Regency in exchange for 3,000,000 Preferred Units having an aggregate liquidation preference of $300 million;
•	acquired from ETP an indirect 49.9% interest in Midcontinent Express Pipeline LLC (“MEP”), ETP’s joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”) to operate the Midcontinent Express Pipeline, and an option to acquire an additional 0.1% interest in MEP in exchange for the redemption by ETP of approximately 12 million ETP Common Units we previously owned; and
•	acquired 26 million Regency Common Units in exchange for our contribution of all of our interests in MEP, including the option to acquire an additional 0.1% interest, to Regency.
We accounted for the Regency Transactions using the purchase method of accounting. The purchase price was $305 million, which was the fair value of the 3,000,000 Preferred Units exchanged in connection with the Regency Transactions.
Other Acquisitions
In March 2010, ETP purchased a natural gas gathering company, which provides dehydration, treating, redelivery and compression services on a 120-mile pipeline system in the Haynesville Shale for approximately $150 million in cash, excluding certain adjustments as defined in the purchase agreement. In connection with this transaction, ETP recorded customer contracts of $68 million and goodwill of $27 million.
In September 2010, Regency completed its acquisition of Zephyr, a Texas based field services company for approximately $193 million in cash. In connection with this transaction, Regency recorded intangible assets of $119 million and no goodwill.
Dispositions
In July 2010, Regency sold its East Texas gathering and processing assets to an affiliate of Tristream Energy LLC for approximately $70 million in cash. The net loss from these assets is classified as discontinued operations in the consolidated statements of operations from the date of the Regency Transactions to the date of the sale.
Pro Forma Results of Operations
The following unaudited pro forma consolidated results of operations for the years ended 2012 and 2011 are presented as if the Sunoco Merger and Holdco Transaction had been completed on January 1, 2011 and the LDH Acquisition had been completed on January 1, 2010.
	Year Ended December 31,
	2012				2011				2010
Revenues	$	40,398			$	37,560			$	7,407
Net income	868				865				358
Net income attributable to partners	866				863				228
Basic net income (loss) per Limited Partner unit	$	3.09			$	3.08			$	1.02
Diluted net income (loss) per Limited Partner unit	$	3.09			$	3.08			$	1.02
The pro forma consolidated results of operations include adjustments to:
•	include the results of Lone Star beginning January 1, 2010 and Southern Union and Sunoco beginning January 1, 2011;
•	include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting; and
•include incremental interest expense related to the financing of ETP’s proportionate share of the purchase price.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

Advances_to_and_Investments_in

Advances to and Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2012
Investment In Affiliates [Abstract]	'
Investments In Affiliates	'
	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
	AmeriGas Partners, L.P.
	On January 12, 2012, ETP contributed its Propane Business to AmeriGas in exchange for approximately $1.46 billion in cash and approximately 30 million AmeriGas Common Units valued at $1.12 billion at the time of the contribution. In addition, AmeriGas assumed approximately $71 million of existing debt of the Propane Business. ETP recognized a gain on deconsolidation of $1.06 billion as a result of this transaction.
	ETP’s investment in AmeriGas initially reflected $630 million in excess of the proportionate share of AmeriGas’ limited partners’ capital. Of this excess fair value, $289 million is being amortized over a weighted average period of 14 years and $341 million is being treated as equity method goodwill and non-amortizable intangible assets.
	We have not reflected the Propane operations as discontinued operations as a result of ETP’s investment in AmeriGas.
	In June 2012, ETP sold the remainder of its retail propane operations, consisting of its cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and ETP received net proceeds of approximately $43 million.
	ETP’s investment in AmeriGas was $1.02 billion as of December 31, 2012 and was reflected in our Investment in ETP segment.
	Citrus Corp.
	ETP acquired a 50% interest in Citrus, which owns 100% of FGT on March 26, 2012. A subsidiary of Kinder Morgan, Inc. owns the remaining 50% interest in Citrus. In exchange for the interest in Citrus, Southern Union received $1.9 billion in cash and $105 million of ETP Common Units. ETP initially recorded its investment in Citrus at $2.0 billion, which exceeded its proportionate share of Citrus’ equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting. ETP’s investment in Citrus was $1.98 billion at December 31, 2012 and is reflected in our Investment in ETP segment.
	Fayetteville Express Pipeline LLC
	ETP owns a 50% interest in 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 in Panola County, Mississippi.
	Midcontinent Express Pipeline LLC
	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.
	RIGS Haynesville Partnership Co.
	Regency owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system.
	Summarized Financial Information
	The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis for all periods presented).
		December 31,
		2012		2011
	Current assets	$	945	$	893
	Property, plant and equipment, net	10,979		10,393
	Other assets	2,677		962
	Total assets	$	14,601	$	12,248
	Current liabilities	$	1,662	$	1,548
	Non-current liabilities	7,024		5,778
	Equity	5,915		4,922
	Total liabilities and equity	$	14,601	$	12,248
		Years Ended December 31,
		2012		2011		2010
	Revenue	$	4,492	$	3,784	$	3,287
	Operating income	863		928		716
	Net income	491		536		506

Net_Income_Per_Limited_Partner

Net Income Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2012
Earnings Per Share [Abstract]	'
Net Income Per Limited Partner Unit	'
	NET INCOME PER LIMITED PARTNER UNIT:
	Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of our Preferred Units, see Note 7. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or Regency that would have resulted assuming the incremental units related to ETP’s or Regency’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.
	The calculation below for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive. The Preferred Units have a liquidation preference of $300 million and are subject to mandatory conversion as discussed in Note 7.
	A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
		Years Ended December 31,
		2012			2011			2010
	Income from continuing operations	$	1,383		$	531		$	345
	Less: Income from continuing operations attributable to noncontrolling interest	1,070			221			149
	Income from continuing operations, net of noncontrolling interest	313			310			196
	Less: General Partner’s interest in income from continuing operations	1			1			1
	Income from continuing operations available to Limited Partners	$	312		$	309		$	195
	Basic Income from Continuing Operations per Limited Partner Unit:
	Weighted average limited partner units	266,722,030			222,968,261			222,941,156
	Basic income from continuing operations per Limited Partner unit	$	1.17		$	1.39		$	0.87
	Basic loss from discontinued operations per Limited Partner unit	$	(0.04	)	$	—		$	(0.01	)
	Diluted Income from Continuing Operations per Limited Partner Unit:
	Income from continuing operations available to Limited Partners	$	312		$	309		$	195
	Dilutive effect of equity-based compensation of subsidiaries	(1		)	(1		)	—
	Diluted income from continuing operations available to Limited Partners	311			308			195
	Weighted average limited partner units	266,722,030			222,968,261			222,941,156
	Diluted income from continuing operations per Limited Partner unit	$	1.17		$	1.38		$	0.87
	Diluted loss from discontinued operations per Limited Partner unit	$	(0.04	)	$	—		$	(0.01	)

Debt_Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2012
Debt Obligations [Abstract]	'
Debt Obligations	'
	DEBT OBLIGATIONS:
	Our debt obligations consist of the following:
		December 31,
		2012			2011
	Parent Company Indebtedness:
	ETE Senior Notes, due October 15, 2020	$	1,800		$	1,800
	ETE Senior Secured Term Loan, due March 26, 2017	2,000			—
	ETE Senior Secured Revolving Credit Facility	60			72
	Other	19			1
	Unamortized premiums, discounts and fair value adjustments, net	(34		)	(1		)
		3,845			1,872
	Subsidiary Indebtedness:
	ETP Debt
	5.65% Senior Notes due August 1, 2012	—			400
	6.0% Senior Notes due July 1, 2013	350			350
	8.5% Senior Notes due April 15, 2014	292			350
	5.95% Senior Notes due February 1, 2015	750			750
	6.125% Senior Notes due February 15, 2017	400			400
	6.7% Senior Notes due July 1, 2018	600			600
	9.7% Senior Notes due March 15, 2019	400			600
	9.0% Senior Notes due April 15, 2019	450			650
	4.65% Senior Notes due June 1, 2021	800			800
	5.20% Senior Notes due February 1, 2022	1,000			—
	6.625% Senior Notes due October 15, 2036	400			400
	7.5% Senior Notes due July 1, 2038	550			550
	6.05% Senior Notes due June 1, 2041	700			700
	6.5% Senior Notes due February 1, 2042	1,000			—
	ETP $2.5 billion Revolving Credit Facility due October 27, 2016	1,395			314
	Other	—			81
	Unamortized premiums, discounts and fair value adjustments, net	(14		)	(2		)
		9,073			6,943
	Panhandle Debt
	6.05% Senior Notes due August 15, 2013	250			—
	6.2% Senior Notes due November 1, 2017	300			—
	7.0% Senior Notes due June 15, 2018	400			—
	8.125% Senior Notes due June 1, 2019	150			—
	7.0% Senior Notes due July 15, 2029	66			—
	Term Loan due February 23, 2015	455			—
	Unamortized premiums, discounts and fair value adjustments, net	136			—
		1,757			—
	Regency Debt
	9.375% Senior Notes due June 1, 2016	162			250
	6.875% Senior Notes due December 1, 2018	600			600
	6.5% Senior Notes due July 15, 2021	500			500
	5.5% Senior Notes due April 15, 2023	700			—
	Regency Revolving Credit Facility	192			332
	Unamortized premiums, discounts and fair value adjustments, net	3			5
		2,157			1,687
	Southern Union Debt
	7.6% Senior Notes due February 1, 2024	360			—
	8.25% Senior Notes due November 14, 2029	300			—
	7.2% Junior Subordinated Notes due November 1, 2066	600			—
	Southern Union Revolving Credit Facility	210			—
	Other	7			—
	Unamortized premiums, discounts and fair value adjustments, net	49			—
		1,526			—
	Sunoco Debt
	4.875% Senior Notes due October 15, 2014	250			—
	9.625% Senior Notes due April 15, 2015	250			—
	5.75% Senior Notes due January 15, 2017	400			—
	9.00% Debentures due November 1, 2024	65			—
	Other	25			—
	Unamortized premiums, discounts and fair value adjustments, net	104			—
	1,094			—
Sunoco Logistics Debt
8.75% Senior Notes due February 15, 2014	175			—
6.125% Senior Notes due May 15, 2016	175			—
5.50% Senior Notes due February 15, 2020	250			—
4.65% Senior Notes due February 15, 2022	300			—
6.85% Senior Notes due February 15, 2040	250			—
6.10% Senior Notes due February 15, 2042	300			—
Sunoco Logistics $200 million Revolving Credit Facility due August 21, 2013	26			—
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015	20			—
Sunoco Logistics $350 million Revolving Credit Facility due August 22, 2016	93			—
Unamortized premiums, discounts and fair value adjustments, net	143			—
	1,732			—
Transwestern Debt
5.39% Senior Notes due November 17, 2014	88			88
5.54% Senior Notes due November 17, 2016	125			125
5.64% Senior Notes due May 24, 2017	82			82
5.36% Senior Notes due December 9, 2020	175			175
5.89% Senior Notes due May 24, 2022	150			150
5.66% Senior Notes due December 9, 2024	175			175
6.16% Senior Notes due May 24, 2037	75			75
Unamortized premiums, discounts and fair value adjustments, net	(1		)	(1		)
	869			869
	22,053			11,371
Current maturities	(613		)	(424		)
	$	21,440		$	10,947
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $386 million in unamortized premiums and fair value adjustments, net:
2013	$	613
2014	1,003
2015	1,540
2016	2,073
2017	3,184
Thereafter	13,254
Total	$	21,667
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the
termination of the interest rate swap.
ETP as Co-Obligor of Sunoco Debt
In connection with the Sunoco Merger and Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco’s existing senior notes and debentures.
Senior Notes
ETE Senior Notes
We used the net proceeds from our Senior Secured Term Loan, along with proceeds received from ETP in the Citrus Acquisition, to fund the cash portion of the Southern Union Merger and pay related fees and expenses, including existing borrowings under our revolving credit facility and for general partnership purposes.
Borrowings bear interest at either the Eurodollar rate plus an applicable margin or the alternative base rate plus an applicable margin. The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, and an adjusted one-month LIBOR rate plus 1.00%. The applicable margins are 3.0% for Eurodollar loans and from 2.0% for base rate loans. The effective interest rate on the amount outstanding as of December 31, 2012 was 3.75%.
The ETE Senior Notes are unsecured obligations of ETE and the obligation to repay the ETE Senior Notes is not guaranteed by any of ETE’s subsidiaries, including ETP, Regency, and their respective subsidiaries. The indebtedness of ETP and Regency and their respective subsidiaries effectively ranks senior to the ETE Senior Notes.
Southern Union Junior Subordinated Notes
Southern Union has interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on $525 million of the $600 million Junior Subordinated Notes due 2066. The interest rate on the remaining notes is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the Junior Subordinated Notes was $75 million at an effective interest rate of 3.32% at December 31, 2012.
Panhandle Term Loans
In February 2012, Southern Union refinanced LNG Holdings’ $455 million term loan due March 2012 with an unsecured three-year term loan facility due February 23, 2015, with LNG Holdings as borrower and PEPL and Trunkline LNG as guarantors and a floating interest rate tied to LIBOR plus a margin based on the rating of PEPL’s senior unsecured debt. The effective interest rate of PEPL’s term loan was 1.84% at December 31, 2012.
Bridge Term Loan Facility
Upon obtaining permanent financing for the Southern Union Merger in March 2012, we terminated the 364-day Bridge Term Loan Facility. For the year ended December 31, 2012, bridge loan related fees reflects the recognition of $62 million of commitment fees upon termination of the facility.
ETP Senior Notes
The ETP Senior Notes are unsecured obligations of ETP and the obligation of ETP to repay the ETP Senior Notes is not guaranteed by us or any of ETP’s subsidiaries. The ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of ETP’s existing and future subsidiaries. The balance is payable upon maturity. Interest on the ETP Senior Notes is paid semi-annually.
January 2013 Senior Notes Offering
In January 2013, ETP completed a public offering of $800 million aggregate principal amount of our 3.6% Senior Notes due February 1, 2023 and $450 million aggregate principal amount of its 5.15% Senior Notes due February 1, 2043. ETP used the net proceeds of approximately $1.24 billion from this offering to repay borrowings outstanding under its revolving credit facility and for general partnership purposes.
In addition, in January 2013, Sunoco Logistics issued $350 million of 3.45% Senior Notes and $350 million of 4.95% Senior Notes (the “2023 and 2043 Senior Notes”), due January 2023 and January 2043, respectively. The terms and conditions of the 2023 and 2043 Senior Notes are comparable to those under Sunoco Logistics’ existing Senior Notes. The net proceeds of $691 million from the 2023 and 2043 Senior Notes were used to pay outstanding borrowings under the $350 million and $200 million Sunoco Logistics Credit Facilities and for general partnership purposes.
Transwestern Senior Notes
The Transwestern Pipeline Company, LLC (“Transwestern”) notes are payable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually.
Regency Senior Notes
The Regency Senior Notes are unsecured obligations of Regency and the obligation of Regency to repay the Regency Senior Notes is not guaranteed by us or any of Regency’s subsidiaries. The Regency Senior Notes effectively rank junior to all indebtedness and other liabilities of Regency’s existing and future subsidiaries. Interest is payable semi-annually.
Revolving Credit Facilities
ETE Senior Secured Credit Facility
The Parent Company has a $200 million five-year senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015. Under the Parent Company Credit Agreement, the obligations of ETE are secured by all tangible and intangible assets of ETE and certain of its subsidiaries, including (i) its ownership of ETP Common Units; (ii) ETE’s equity interest in ETP LLC and ETP GP, through which ETE holds the IDRs in ETP; (iii) the Common Units of Regency; and (iv) ETE’s equity interest in Regency GP LLC and Regency GP LP, through which ETE holds the IDRs in Regency.
Borrowings bear interest, at ETE’s option, at either the Eurodollar rate plus an applicable margin or the alternative base rate. The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, and an adjusted one-month LIBOR rate plus 1.00%. The applicable margins are based upon ETE’s leverage ratio and range from 2.75% to 3.75% for Eurodollar loans and from 1.75% to 2.75% for base rate loans. The commitment fee payable on the unused portion of the Parent Company Credit Agreement is based on ETE’s leverage ratio and ranges from 0.50% to 0.75%.
In connection with the Parent Company Credit Agreement, ETE and certain of its subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”). The Security Agreement secures all of ETE’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a continuing first priority lien on, and security interest in, all of ETE’s and the other grantors’ tangible and intangible assets.
As of December 31, 2012, we had a balance of $60 million outstanding under the Parent Company Credit Agreement and the amount available for future borrowings was $140 million. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 4.06%.
ETP Credit Facility
The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as ETP’s other current and future unsecured debt.
On October 27, 2011, ETP amended and restated the ETP Credit Facility to, among other things, (i) allow for borrowings of up to $2.5 billion; (ii) extend the maturity date from July 20, 2012 to October 27, 2016 (which may be extended by one year with lender approval); (iii) allow for an increase in the size of the credit facility to $3.75 billion (subject to obtaining lender commitments for the additional borrowing capacity); and (iv) to adjust the interest rates and commitment fees to current market terms. Following this amendment and based on our current ratings, the interest margin for LIBOR rate loans is 1.50% and the commitment fee for unused borrowing capacity is 0.25%.
ETP used approximately $2.0 billion of Sunoco’s cash on hand to partially fund the cash portion of the Sunoco Merger consideration. The remainder of the cash portion of the merger consideration, approximately $620 million, was funded with borrowings under the ETP Credit Facility.
As of December 31, 2012, ETP had a balance of $1.40 billion outstanding under the ETP Credit Facility and, taking into account letters of credit of approximately $72 million, $1.03 billion available for future borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 1.71%.
Regency Credit Facility
The Regency Credit Facility has aggregate revolving commitments of $1.15 billion, with $200 million of availability for letters of credit that matures June 15, 2014. As of December 31, 2012, Regency had a balance of $192 million outstanding under the Regency Credit Facility in revolving credit loans and approximately $12 million in letters of credit. The total amount available under the Regency Credit Facility, as of December 31, 2012, which is reduced by any letters of credit, was approximately $946 million. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 2.93%.
The outstanding balance of revolving loans under the Regency Credit Facility bears interest at LIBOR plus a margin or an alternate base rate. The alternate base rate used to calculate interest on base rate loans will be calculated using the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.0%. The applicable margin ranges from 1.50% to 2.25% for base rate loans and 2.50% to 3.25% for Eurodollar loans.
Regency pays (i) a commitment fee ranging between 0.375% and 0.50% per annum for the unused portion of the revolving loan commitments; (ii) a participation fee for each revolving lender participating in letters of credit ranging between 2.50% and 3.25% per annum of the average daily amount of such lender’s letter of credit exposure and; (iii) a fronting fee to the issuing bank of letters of credit equal to 0.125% per annum of the average daily amount of its letter of credit exposure. In December 2011, Regency amended its credit facility to allow for additional investments in its joint ventures.
Southern Union Credit Facility
The Southern Union Credit Facility provides for a $700 million revolving credit facility which matures on May 20, 2016. Borrowings under the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based on the credit ratings for Southern Union’s senior unsecured notes. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 1.84%.
On August 10, 2012, Southern Union entered into a First Amendment of the Southern Union Credit Facility. The amendment provides for, among other things, (i) a revision to the change of control definition to permit equity ownership of Southern Union by ETP or any direct subsidiaries of ETP in addition to ETE or any direct or indirect subsidiary of ETE; and (ii) a waiver of any potential default that may result from the Holdco Transaction.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintains two credit facilities to fund the Partnership’s 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 (the “$350 million Credit Facility”) and a $200 million unsecured credit facility which expires in August 2013 (the “$200 million Credit Facility”). Outstanding borrowings under $350 million Credit Facility and $200 million Credit Facility were $93 million and $26 million, respectively, at December 31, 2012.
In May 2012, Sunoco Logistics’ West Texas Gulf entered into a $35 million revolving credit facility (the “$35 million Credit Facility”) which expires in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. Outstanding borrowings under this credit facility were $20 million at December 31, 2012.
Covenants Related to Our Credit Agreements
Covenants Related to the Parent Company
The Parent Company Credit Agreement contains customary representations, warranties and covenants, including financial covenants regarding a maximum leverage ratio, a maximum consolidated leverage ratio, a minimum fixed charge coverage ratio and a minimum loan to value ratio. In addition, the Parent Company Credit Agreement contains customary events of default, including, but not limited to, (i) default for failure to pay the principal on any loan or any reimbursement obligation with respect to any letter of credit when due and payable, (ii) failure to duly observe, perform or comply with certain specified covenants, (iii) a representation or warranty made in connection with any loan document proves to have been false or incorrect in any material respect on any date on or as of which made, and (iv) the occurrence of a change of control.
The Parent Company Senior Secured Revolving Credit Facility contains financial covenants as follows:
•	Maximum Leverage Ratio – Consolidated Funded Debt of the Parent Company (as defined) to Consolidated EBITDA (as defined in the agreements) of the Parent Company of not more than 4.5 to 1, with a permitted increase to 5 to 1 during a specified acquisition period extending for two fiscal quarters following the close of a specified acquisition;
•	Maximum Consolidated Leverage Ratio – Consolidated Funded Debt of the Parent Company, ETP and Regency to Consolidated EBITDA of ETP and Regency of not more than 5.5 to 1;
•	Fixed Charge Coverage Ratio of not less than 3 to 1; and
•	Value to Loan Ratio of not less than 2 to 1.
Covenants Related to ETP
The agreements relating to the ETP Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the ETP’s and certain of the ETP’s subsidiaries’ ability to, among other things:
•	incur indebtedness;
•	grant liens;
•	enter into mergers;
•	dispose of assets;
•	make certain investments;
•	make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement);
•	engage in business substantially different in nature than the business currently conducted by ETP and its subsidiaries;
•	engage in transactions with affiliates; and
•	enter into restrictive agreements.
The credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Covenants Related to Regency
The Regency Senior Notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries, to:
•	incur additional indebtedness;
•	pay distributions on, or repurchase or redeem equity interests;
•	make certain investments;
•	incur liens;
•	enter into certain types of transactions with affiliates; and
•	sell assets, consolidate or merge with or into other companies.
If the Regency Senior Notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to many of the foregoing covenants. The Regency Credit Facility contains the following financial covenants:
•	Regency’s consolidated EBITDA ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.25 to 1.
•	Regency’s consolidated EBITDA to consolidated interest expense, as defined in the credit agreement governing the Regency Credit Facility, must be greater than 2.75 to 1.
•	Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3 to 1.
The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:
•	incur indebtedness;
•	grant liens;
•	enter into sale and leaseback transactions;
•	make certain investments, loans and advances;
•	dissolve or enter into a merger or consolidation;
•	enter into asset sales or make acquisitions;
•	enter into transactions with affiliates;
•	prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);
•	issue capital stock or create subsidiaries; or
•	engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.
Covenants Related to Southern Union
Southern Union is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Southern Union’s lending agreements. Financial covenants exist in certain of the Southern Union’s debt agreements. A failure by Southern Union to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Southern Union did not cure such default within any permitted cure period or if Southern Union did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Southern Union’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the financial covenants are as follows:
•	Under the Southern Union Credit Facility, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, cannot exceed 5.25 times through December 31, 2012 and 5.00 times thereafter;
•	Under the Southern Union Credit Facility, in the event Southern Union’s credit rating falls below investment grade, the ratio of consolidated earnings before interest, taxes, depreciation and amortization to consolidated interest expense, as defined therein, cannot be less than 2.00 times;
•	Under LNG Holding’s $455 million term loan, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, for Panhandle cannot exceed 5.00 times.
In addition to the above financial covenants, Southern Union and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Southern Union’s cash management program; and limitations on Southern Union’s ability to prepay debt.
Covenants Related to Sunoco Logistics
Sunoco Logistics’ $350 and $200 million Credit Facilities contain various covenants limiting the Partnership’s ability to incur indebtedness; grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The credit facilities also limit Sunoco Logistics, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period.
Sunoco Logistics’ $35 million Credit Facility limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio, as defined in the underlying credit agreement. The ratio for the fiscal quarter ending December 31, 2012 shall not be less than 1.00 to 1. The minimum ratio fluctuates between 0.80 to 1 and 1.00 to 1 throughout the term of the revolver as specified in the credit agreement. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1.
Compliance With Our Covenants
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.
We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2012.

Redeemable_Preferred_Units

Redeemable Preferred Units	12 Months Ended
	Dec. 31, 2012
Preferred Units, Preferred Partners' Capital Account [Abstract]	'
Redeemable Preferred Units	'
	REDEEMABLE PREFERRED UNITS:
	ETE Preferred Units
	In connection with the Regency Transactions as discussed in Note 3, ETE issued 3,000,000 Preferred Units to an affiliate of GE Energy Financial Services, Inc. (“GE EFS”) having an aggregate liquidation preference of $300 million and are reflected as long-term liabilities in our consolidated balance sheets as of December 31, 2012 and 2011. The Preferred Units were issued in a private placement at a stated price of $100 per unit and are entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit. The Preferred Units will automatically convert on the fourth anniversary of the date of issuance into an amount of ETE Common Units equal in value to the issue price plus any accrued but unpaid distributions plus a specified premium equal to the lesser of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance of the Preferred Units. ETE may choose, at its sole option, to pay 50% of the conversion consideration based on the issue price plus any accrued but unpaid distributions in cash. ETE may elect to redeem all, but not less than all, of the Preferred Units beginning on the third anniversary of the date of issuance for ETE Common Units or cash equal to the issue price plus a premium paid out in common units, equal to the greater of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance. GE EFS also has certain rights to force ETE to redeem or convert the outstanding Preferred Units for specified consideration upon the occurrence of certain extraordinary events involving ETE or ETP. Holders of the Preferred Units have no voting rights, except that approval of a majority of the Preferred Units is needed to approve any amendment to ETE’s Partnership Agreement that would result in (i) any increase in the size of the class of Preferred Units, (ii) any alteration or change to the rights, preferences, privileges, duties, or obligations of the Preferred Units or (iii) any other matter that would adversely affect the rights or preferences of the Preferred Units, including in relation to other classes of ETE partnership interests. During 2012, we recorded non-cash charges of approximately $8 million to increase the carrying value of the Preferred Units to the estimated fair value of $331 million as of December 31, 2012. During 2011, we recorded non-cash charges of approximately $5 million to increase the carrying value of the Preferred Units to the estimated fair value of $323 million as of December 31, 2011.
	Preferred Units of Subsidiary
	Regency had 4,371,586 Regency Preferred Units outstanding at December 31, 2012, which were convertible into 4,658,700 Regency Common Units. If outstanding on September 2, 2029 the Regency Preferred Units are mandatorily redeemable for $80 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed Regency quarterly cash distributions of $0.445 per unit. Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s partnership agreement.
	The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:
		Regency	Amount
		Preferred
		Units
	Balance, December 31, 2011	4,371,586	$	71
	Accretion to redemption value	—	2
	Balance, December 31, 2012	4,371,586	$	73

Equity

Equity	12 Months Ended
	Dec. 31, 2012
Partners' Capital Notes [Abstract]	'
Equity	'
	EQUITY:
	Limited Partner Units
	Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”
	As of December 31, 2012, there were issued and outstanding 279,955,608 Common Units representing an aggregate 99.75% limited partner interest in the Partnership.
	Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.
	Common Units
	The change in ETE Common Units during the years ended December 31, 2012, 2011 and 2010 was as follows:
		Years Ended December 31,
		2012			2011			2010
	Number of Common Units, beginning of period	222,972,708			222,941,172			222,898,248
	Issuance of restricted Common Units under long-term incentive plan	740			31,536			42,924
	Issuance of common units in connection with Southern Union Merger (See Note 3)	56,982,160			—			—
	Number of Common Units, end of period	279,955,608			222,972,708			222,941,172
	Sale of Common Units by Subsidiaries
	The Parent Company accounts for the difference between the carrying amount of its investment in ETP and Regency and the underlying book value arising from issuance of units by ETP or Regency (excluding unit issuances to the Parent Company) as a capital transaction. If ETP or Regency issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuance of ETP or Regency Common Units during the periods presented.
	As a result of ETP’s and Regency’s issuances and redemptions of Common Units, we have recognized increases in partners’ capital of $80 million, $153 million and $352 million for the years ended December 31, 2012, 2011 and 2010, respectively.
	Sale of Common Units by ETP
	The following table summarizes ETP’s public offerings of ETP Common Units during the periods presented:
	Date		Number of			Price per ETP			Net Proceeds		Use of
			ETP Common			Unit					Proceeds
			Units (1)
	Jan-10		9,775,000			$	44.72		$	424	(2)(3)
	Aug-10		10,925,000			46.22			489		(2)(3)
	Apr-11		14,202,500			50.52			695		(3)
	Nov-11		15,237,500			44.67			660		(2)(3)
	Jul-12		15,525,000			44.57			671		(2)(3)
	(1)	Number of Common Units includes the exercise of the overallotment options by the underwriters.
	(2)	Proceeds were used to repay amounts outstanding under the ETP Credit Facility.
	(3)	Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.
	ETP issued 90,706,000 ETP Class F Units in connection with the Holdco Transaction that are reported as treasury units, which are entitled to receive distributions in accordance with their terms, see Note 3.
	ETP’s Equity Distribution Program
	From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.
	In January 2013, ETP entered into an equity distribution agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated (“BofA Merrill Lynch”). According to the provisions of this agreement, ETP may offer and sell from time to time through BofA Merrill Lynch, as its sales agent, ETP Common Units having an aggregate offering price of up to $200 million. Under the terms of this agreement, ETP may also sell ETP Common Units to BofA Merrill Lynch as principal for its own account at a price agreed upon at the time of sale. Any sale of ETP Common Units to BofA Merrill Lynch as principal would be pursuant to the terms of a separate agreement between us and BofA Merrill Lynch.
	ETP’s Equity Incentive Plan Activity
	As discussed in Note 9, ETP issues ETP Common Units to employees and directors upon vesting of awards grander under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.
	ETP’s Distribution Reinvestment Program
	In April 2011, ETP filed a registration statement with the SEC covering its DRIP. The DRIP provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. The registration statement covers the issuance of up to 5,750,000 Common Units under the DRIP.
	During 2012, distributions of approximately $43 million were reinvested under the DRIP resulting in the issuance of 1,038,825 ETP Common Units.
	Sale of Common Units by Regency
	The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented:
	Date		Number of			Price per			Net Proceeds		Use of
			Regency Common			Regency Unit					Proceeds
			Units (1)
	Aug-10		17,537,500			$	23.8		$	400	(2)
	May-11		8,500,001			(4		)	204		(3)
	Oct-11		11,500,000			20.92			232		(2)
	Mar-12		12,650,000			24.47			297		(2)(3)
	(1)	Number of Common Units includes the exercise of the overallotment options by the underwriters.
	(2)	Proceeds were used to repay amounts outstanding under the Regency Credit Facility.
	(3)	Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.
	(4)	Regency Units were issued in a private placement.
	On June 19, 2012, Regency entered into an Equity Distribution Agreement with Citi under which Regency may offer and sell Regency Common Units, having an aggregate offering price of up to $200 million from time to time through Citi, as sales agent for Regency. Sales of these units, if any, made under the Regency Equity Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by Regency and Citi. Under the terms of this agreement, Regency may also sell Regency Common Units to Citi as principal for its own account at a price agreed upon at the time of sale. Any sale of Regency Common Units to Citi as principal would be pursuant to the terms of a separate agreement between Regency and Citi. Regency intends to use the net proceeds from the sale of these units for general partnership purposes. During the year ended December 31, 2012, Regency issued 691,129 Regency Common Units pursuant to its Equity Distribution Agreement with Citi and received net proceeds of $15 million.
	Contributions to Subsidiaries
	The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. In order to maintain its general partner interest in ETP, ETP GP was previously required to make contributions to ETP each time ETP issued limited partner interests for cash or in connection with acquisitions. These contributions were generally paid by offsetting the required contributions against the funds ETP GP receives from ETP distributions on the general partner and limited partner interests owned by ETP GP. In July 2009, ETP amended and restated its partnership agreement, and as a result, ETP GP is no longer required to make corresponding contributions to maintain its general partner interest in ETP.
	The Parent Company owns the entire general partner interest in Regency through its ownership of Regency GP. Regency GP has the right, but not the obligation, to contribute a proportionate amount of capital to Regency to maintain its current general partner interest. Regency GP’s interest in Regency’s distributions is reduced if Regency issues additional units and Regency GP does not contribute a proportionate amount of capital to Regency to maintain its General Partner interest.
	Parent Company Quarterly Distributions of Available Cash
	Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Regency related to limited and general partner interests, including IDRs, and distributions related to its 60% interest in Holdco. We currently have no independent operations outside of our direct and indirect interests in ETP, Regency and Holdco.
	Our distributions declared during the years ended December 31, 2012, 2011 and 2010 are summarized as follows:
	Quarter Ended		Record Date		Payment Date		Distribution per
							ETE Common Unit
	30-Sep-12		6-Nov-12		16-Nov-12		$	0.625
	30-Jun-12		6-Aug-12		17-Aug-12		0.625
	31-Mar-12		4-May-12		18-May-12		0.625
31-Dec-11		7-Feb-12		17-Feb-12		0.625
30-Sep-11		4-Nov-11		18-Nov-11		$	0.625
30-Jun-11		5-Aug-11		19-Aug-11		0.625
31-Mar-11		6-May-11		19-May-11		0.56
31-Dec-10		7-Feb-11		18-Feb-11		0.54
30-Sep-10		8-Nov-10		19-Nov-10		$	0.54
30-Jun-10		9-Aug-10		19-Aug-10		0.54
31-Mar-10		7-May-10		19-May-10		0.54
31-Dec-09		8-Feb-10		19-Feb-10		0.54
On January 28, 2013, the Parent Company declared a cash distribution for the three months ended December 31, 2012 of $0.635 per Common Unit, or $2.54 annualized. We paid this distribution on February 19, 2013 to Unitholders of record at the close of business on February 7, 2013.
ETP’s Quarterly Distribution of Available Cash
ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its General Partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s Partnership Agreement.
ETP’s distributions declared during the periods presented below are summarized as follows:
Quarter Ended		Record Date		Payment Date		Distribution per
						ETP Common Unit
30-Sep-12		6-Nov-12		14-Nov-12		$	0.89375
30-Jun-12		6-Aug-12		14-Aug-12		0.89375
31-Mar-12		4-May-12		15-May-12		0.89375
31-Dec-11		7-Feb-12		14-Feb-12		0.89375
30-Sep-11		November 4, 2011		November 14, 2011		$	0.89375
30-Jun-11		August 5, 2011		August 15, 2011		0.89375
31-Mar-11		May 6, 2011		May 16, 2011		0.89375
31-Dec-10		February 7, 2011		February 14, 2011		0.89375
30-Sep-10		November 8, 2010		November 15, 2010		$	0.89375
30-Jun-10		August 9, 2010		August 16, 2010		0.89375
31-Mar-10		May 7, 2010		May 17, 2010		0.89375
31-Dec-09		February 8, 2010		February 15, 2010		0.89375
On January 28, 2013, ETP declared a cash distribution for the three months ended December 31, 2012 of $0.89375 per ETP Common Unit, or $3.575 annualized. ETP paid this distribution on February 14, 2013 to ETP Unitholders of record at the close of business on February 7, 2013.
Regency’s Quarterly Distribution of Available Cash
Regency’s Partnership Agreement requires that Regency distribute all of its Available Cash to its Unitholders and its General Partner within 45 days after the end of each quarter to unitholders of record on the applicable record date, as determined by the general partner. The term Available Cash generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the general partner to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to the unitholders and to the General Partner for any one or more of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.
Distributions paid by Regency since the date of acquisition are summarized as follows:
Quarter Ended		Record Date		Payment Date		Distribution per
						Regency Common
						Unit
September 30, 2012		6-Nov-12		14-Nov-12		$	0.46
June 30, 2012		6-Aug-12		14-Aug-12		0.46
March 31, 2012		7-May-12		14-May-12		0.46
December 31, 2011		6-Feb-12		13-Feb-12		0.46
30-Sep-11		7-Nov-11		14-Nov-11		$	0.455
30-Jun-11		5-Aug-11		12-Aug-11		0.45
31-Mar-11		6-May-11		13-May-11		0.445
31-Dec-10		7-Feb-11		14-Feb-11		0.445
30-Sep-10		November 5, 2010		November 12, 2010		$	0.445
30-Jun-10		August 6, 2010		August 13, 2010		0.445
On January 28, 2013, Regency declared a cash distribution for the three months ended December 31, 2012 of $0.46 per Regency Common Unit, or $1.84 annualized. Regency paid this distribution on February 14, 2013 to Regency Unitholders of record at the close of business on February 7, 2013.
Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
	December 31,
	2012				2011
Net gains (losses) on commodity related hedges	$	(3	)		$	2
Actuarial loss related to pensions and other postretirement benefits	(10		)		—
Equity investments, net	(9		)		—
Subtotal	(22		)		2
Amounts attributable to noncontrolling interest	10				(1		)
Total AOCI included in partners’ capital, net of tax	$	(12	)		$	1
The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented:
	December 31,
	2012				2011
Net gains on commodity related hedges	$	2			$	—
Actuarial loss relating to pension and other postretirement benefits	5				—
Total	$	7			$	—

UnitBased_Compensation_Plans

Unit-Based Compensation Plans	12 Months Ended
	Dec. 31, 2012
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]	'
Unit-Based Compensation Plans	'
	UNIT-BASED COMPENSATION PLANS:
	We, ETP, Sunoco Logistics and Regency have issued 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, distribution equivalent rights (“DERs”), common unit appreciation rights, and other unit-based awards.
	ETE Long-Term Incentive Plan
	The Board of Directors or the Compensation Committee of the board of directors of the our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 3,000,000 units. As of December 31, 2012, 2,852,936 units remain available to be awarded under the plan.
	During 2012, no awards were granted to ETE employees and 740 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest ratably over three years and do not entitle the holders to receive distributions during the vesting period.
	During 2012, a total of 28,325 ETE units vested, with a total fair value of $1 million as of the vesting date. As of December 31, 2012, a total of 54,972 restricted units granted to ETE employees and directors remain outstanding, for which we expect to recognize a total of $1 million in compensation over a weighted average period of 1.9 years.
	ETP Unit-Based Compensation Plans
	Unit Grants
	ETP has granted restricted unit awards to employees that vest over a specified time period, typically a five-year period at 20% per year, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each ETP Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per ETP Common Unit made by ETP on its Common Units promptly following each such distribution by ETP to its Unitholders. We refer to these rights as “distribution equivalent rights.”
	Under ETP’s equity incentive plans, its non-employee directors each receive grants that vest ratably over three years and do not entitle the holders to receive distributions during the vesting period.
	Award Activity
	The following table shows the activity of the ETP awards granted to employees and non-employee directors:
		Number of		Weighted Average
		ETP Units		Grant-Date Fair
				Value Per ETP
				Unit
	Unvested awards as of December 31, 2011	2,563,709		$	46.37
	Awards granted	289,930		43.93
	Awards vested	(647,498	)	44.58
	Awards forfeited	(346,982	)	44.58
	Unvested awards as of December 31, 2012	1,859,159		46.95
	During the years ended December 31, 2012, 2011 and 2010, the weighted average grant-date fair value per unit award granted was $43.93, $48.35 and $49.82, respectively. The total fair value of awards vested was $29 million, $27 million and $17 million, respectively based on the market price of ETP Common Units as of the vesting date. As of December 31, 2012, a total of 1,859,159 unit awards remain unvested, for which ETP expects to recognize a total of $51 million in compensation expense over a weighted average period of 1.8 years.
	Sunoco Logistics Unit-Based Compensation Plan
	Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco Logistics covering an additional 0.9 million Sunoco common units. As of December 31, 2012, a total of 427,610 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $10 million of expense over a weighted-average period of 2.5 years.
	Related Party Awards
	McReynolds Energy Partners, L.P., the general partner of which is owned and controlled by an ETE officer, awarded to certain officers of ETP certain rights related to units of ETE previously issued by ETE to such ETE officer. These rights include the economic benefits of ownership of these ETE units based on a five-year vesting schedule whereby the ETP officers will vest in the ETE units at a rate of 20% per year. As these ETE units are conveyed to the recipients of these awards upon vesting from a partnership that is not owned or managed by ETE or ETP, none of the costs related to such awards are paid by ETP or ETE unless this partnership defaults under its obligations pursuant to these unit awards. As these units were outstanding prior to these awards, these awards do not represent an increase in the number of outstanding units of either ETP or ETE and are not dilutive to cash distributions per unit with respect to either ETP or ETE.
	ETP is recognizing non-cash compensation expense over the vesting period based on the grant-date fair value of the ETE units awarded to the ETP employees assuming no forfeitures. For the years ended December 31, 2012, 2011 and 2010, ETP recognized non-cash compensation expense, net of forfeitures, of $1 million, $2 million and $4 million, respectively, as a result of these awards. As of December 31, 2012, rights related to 90,000 ETE common units remain outstanding, for which ETP expects to recognize a total of less than $1 million in compensation expense over a weighted average period of 0.6 years.
	Regency Unit-Based Compensation Plans
	Regency has the following awards outstanding as of December 31, 2012:
	•	156,550 Regency Common Unit options, all of which are exercisable, with a weighted average exercise price of $21.96 per unit option;
	•	no Regency restricted (non-vested) Common Units; and
	•	1,226,542 Regency Phantom Units, with a weighted average grant date fair value of $23.22 per Phantom Unit.
	In conjunction with the Regency Transactions, certain of Regency’s then-outstanding Phantom Units converted to 252,630 Regency Common Units as a result of change-in-control provisions associated with the awards. Each of Regency’s outstanding Phantom Units as of December 31, 2012 is the economic equivalent of one Regency Common Unit and is accompanied by a distribution equivalent right, entitling the holder to an amount equal to any cash distributions paid on Regency Common Units. The outstanding Regency Phantom Units will vest one-third on each March 15th through 2013.
	Regency expects to recognize $26 million of compensation expense related to the Regency Phantom Units over a weighted average period of five years.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2012
Income Taxes [Abstract]	'
Income Tax Disclosure [Text Block]	'
	INCOME TAXES:
	As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:
		Years Ended December 31,
		2012			2011			2010
	Current expense (benefit):
	Federal	$	(3	)	$	(1	)	$	1
	State	6			17			9
	Total	3			16			10
	Deferred expense:
	Federal	41			—			3
	State	10			1			1
	Total	51			1			4
	Total income tax expense from continuing operations	$	54		$	17		$	14
	Historically, our effective tax rate differed from the statutory rate primarily due to partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union, Sunoco and Holdco transactions (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the year ended December 31, 2012 is a as follows:
		Holdco (1)			Other Corporate Subsidiaries (2)			Partnership (3)		Consolidated
	Income tax expense (benefit) at U.S. statutory rate of 35%	$	(1	)	$	(3	)	$	—	$	(4	)
	Increase (reduction) in income taxes resulting from:
	Nondeductible executive compensation	28			—			—		28
	State income taxes (net of federal income tax effects)	9			—			2		11
	Other	17			2			—		19
	Income Tax from continuing operations	$	53		$	(1	)	$	2	$	54
	(1)	Holdco, which was formed via the Sunoco Merger and the Holdco transactions (see Note 3), includes Sunoco and Southern Union and their subsidiaries.
	(2)	Includes Oasis Pipeline Company, Pueblo Holdings Inc. (Pueblo), Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. The latter three entities were acquired in the Sunoco transaction.
	(3)	Includes Energy Transfer Equity, L.P. and its subsidiaries that are classified as pass-through entities for federal income tax purposes.
	Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
		December 31,
		2012			2011
	Deferred tax assets:
	Net operating losses and alternative minimum tax credit	$	270		$	4
	Pension and other postretirement benefits	127			—
	Long term debt	117			—
	Other	290			4
	Total deferred income tax assets	804			8
	Valuation allowance	(94		)	(3		)
	Net deferred income tax assets	710			5
	Deferred income tax liabilities:
	Properties, plants and equipment	(2,026		)	(147		)
	Inventory	(516		)	—
	Investments in unconsolidated affiliates	(1,543		)	(72		)
	Trademarks	(192		)	—
	Other	(129		)	—
	Total deferred income tax liabilities	(4,406		)	(219		)
	Net deferred income tax liability	(3,696		)	(214		)
	Less: current portion of deferred income tax asset (liabilities)	(130		)	3
	Accumulated deferred income taxes	$	(3,566	)	$	(217	)
	The completion of the Southern Union, Sunoco and Holdco transactions (see Note 3) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:
		December 31,
		2012
	Net deferred income tax liability, beginning of year	$	(214	)
	Southern Union acquisition	(1,428		)
	Sunoco acquisition	(1,989		)
	Tax provision (including discontinued operations)	(62		)
	Other	(3		)
	Net deferred income tax liability	$	(3,696	)
	Holdco and other corporate subsidiaries have gross federal net operating loss carryforwards of $368 million, of which $1 million, $3 million, $18 million, $40 million and $306 million will expire in 2028, 2029, 2030, 2031 and 2032, respectively. Holdco has $37 million of federal alternative minimum tax credit which do not expire. Holdco and other corporate subsidiaries have state net operating loss carryforward benefits of $104 million, net of federal tax which expire between 2013 and 2032. The valuation allowance is applicable to the federal net operating loss benefits and state net operating loss benefits of $4 million and $90 million, respectively. The valuation allowance of $90 million for state net operating loss benefits is applicable to Sunoco pre-acquisition periods. The valuation for federal net operating loss benefits increased $1 million in 2012.
	The following table sets forth the changes in unrecognized tax benefits:
		Years Ended December 31,
		2012			2011			2010
	Balance at beginning of year	$	2		$	2		$	1
	Additions attributable to acquisitions	28			—			—
	Additions attributable to tax positions taken in the current year	—			1			—
	Additions attributable to tax positions taken in prior years	—			—			1
	Lapse of statute	(3		)	(1		)	—
Balance at end of year	$	27		$	2		$	2
As of December 31, 2012, we have $24 million ($16 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $5 million ($3 million, net of federal tax) within the next 12 months due to settlement of certain positions.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2012, we recognized interest and penalties of less than $1 million. At December 31, 2012, we have interest and penalties accrued of $5 million, net of tax.
In general, ETE and its subsidiaries are no longer subject to examination by the Internal Revenue Service for tax years prior to 2009, except Sunoco, Regency and Pueblo which are no longer subject to examination by the IRS for tax years prior to 2007 and Southern Union which is no longer subject to examination by the IRS for tax years prior to and 2004.
Sunoco has been examined by the IRS for the 2007 and 2008 tax years, however, the statutes remain open for both of these tax years due to carryback of net operating losses.  Southern Union is under examination for the tax years 2004 through 2009. As of December 31, 2012, the IRS has proposed only one adjustment for the years under examination. For the 2006 tax year, the IRS is challenging $545 million of the $690 million of deferred gain associated with a like kind exchange involving certain assets of its distribution operations and its gathering and processing operations. We will vigorously defend and believe Southern Union’s tax position will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to this tax position.  Regency and Pueblo are also under examination by the IRS for the 2007 and 2008 and the 2007 to 2009 tax years, respectively. The IRS has proposed adjustments in both of these examinations which are under review at the Appeals level. We believe Regency and Pueblo will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to these tax positions. Neither of the proposed adjustments with respect to Regency or Pueblo would have a material impact upon our financial statements.
ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

Regulatory_Matters_Commitments

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	12 Months Ended
	Dec. 31, 2012
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]	'
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	'
	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES:
	Regulatory Matters
	Southern Union and its Subsidiaries
	The FERC is currently conducting an audit of PEPL, a subsidiary of Southern Union, 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. The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.
	Contingent Residual Support Agreement - AmeriGas
	In order to finance the cash portion of the purchase price of the Propane Transaction described in Note 3, AmeriGas Finance LLC (”Finance Company”), a wholly owned subsidiary of AmeriGas, issued $550 million in aggregate principal amount of 6.75% senior notes due 2020 and $1.0 billion in aggregate principal amount of 7.00% senior notes due 2022. AmeriGas borrowed $1.5 billion of the proceeds of the Senior Notes issuance from Finance Company through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes (the “Supported Debt”).
	In connection with the closing of the Propane Transaction, ETP entered into and delivered a Contingent Residual Support Agreement (”CRSA”) with AmeriGas, Finance Company, AmeriGas Finance Corp. and UGI Corp., pursuant to which ETP will provide contingent, residual support of the Supported Debt as defined in the CRSA.
	Commitments
	In the normal course of business, ETP and Regency purchase, process and sell natural gas pursuant to long-term contracts and 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 its 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 approximately $60 million, $29 million and $24 million for the years ended December 31, 2012, 2011 and 2010, respectively, which include contingent rentals totaling $6 million in 2012. During the three months ended December 31, 2012, approximately $4 million of rental expense was recovered through related sublease rental income.
	Future minimum lease commitments for such leases are:
	Years Ending December 31:
	2013	$	92
	2014	82
	2015	79
	2016	64
	2017	52
	Thereafter	462
	Future minimum lease commitments	831
	Less: Sublease rental income	(64		)
	Net future minimum lease commitments	$	767
	Amounts reflected above do not include future minimum lease commitments for the Southern Union’s distribution operations, which were reclassified and reported as assets and liabilities held for sale at December 31, 2012 as described in Note 3.
	ETP and Regency’s joint venture agreements require that they fund their proportionate share 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.
	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 December 31, 2012 and 2011, accruals of approximately $15 million and $18 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 the resolution of a particular contingency based on changes in facts and circumstances or in the expected outcome.
	No amounts have been recorded in our December 31, 2012 or 2011 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
	Will Price. Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including Panhandle, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On September 19, 2009, the Court denied plaintiffs’ request for class certification. Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010. Panhandle believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by the FERC. As a result, Southern Union believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Panhandle complied with the terms of its tariffs). In the event that Plaintiffs refuse Panhandle’s pending request for voluntary dismissal, Panhandle will continue to vigorously defend the case. Southern Union believes it has no liability associated with this proceeding.
	Attorney General of the Commonwealth of Massachusetts v New England Gas Company. On July 7, 2011, the Massachusetts Attorney General filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries. The Attorney General 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 Attorney General 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 Vice Chairman, President and COO, 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 Attorney General contends only would 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 stayed discovery until resolution of a separate matter concerning the applicability of attorney-client privilege to legal billing invoices. 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. Additionally, New England Gas Company’s assets and liabilities have been included in discontinued operations at December 31, 2012.
	Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ.
	Compliance Orders from the New Mexico Environmental Department. SUGS has been in discussions with the New Mexico Environmental Department concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. The New Mexico Environmental Department has issued amended compliance orders and proposed penalties for alleged violations at Jal #4 in the amount of $1 million and at Jal #3 in the amount of $7 million. Hearings on the compliance orders were delayed until May 2013 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the New Mexico Environmental Department claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.
	FGT Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGT’s mainline pipelines located in FDOT/FTE rights-of-way. Several FDOT/FTE projects are the subject of litigation in Broward County, Florida. On January 27, 2011, a jury awarded FGT $83 million and rejected all damage claims by the FDOT/FTE. On May 2, 2011, the judge issued an order entitling FGT to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space. The judge further ruled that FGT is entitled to approximately $8 million in interest. In addition to ruling on other aspects of the easement, he ruled that pavement could not be placed directly over FGT’s pipeline without the consent of FGT although FGT would be required to relocate the pipeline if it did not provide such consent. While FGT would seek reimbursement of any costs associated with relocation of its pipeline in connection with an FDOT project, FGT may not be successful in obtaining such reimbursement and, as such, could be required to bear the cost of such relocation. In any such instance, FGT would seek recovery of the reimbursement costs in rates. The judge also denied all other pending post-trial motions. The FDOT/FTE filed a notice of appeal on July 12, 2011. On June 6, 2012, Florida’s Fourth District Court of Appeal (“4th DCA”)  issued an opinion affirming the jury award of damages and also affirming or remanding for further consideration by the trial court certain other determinations with respect to FGT’s easement rights and FDOT/FTE’s obligations regarding future FDOT/FTE projects.  In particular, the 4th DCA affirmed that FDOT/FTE could not pave directly over our pipeline without FBT’s consent and remanded and directed the trial court to make reference in the final judgment to FDOT/FTE’s obligation to seek reasonable alternatives to relocation.  The 4th DCA did overturn the portion of the trial court judgment defining the width of FGT’s easements as 15 feet on either side of its pipelines and defining the temporary work space available to Florida Gas under its easements as 75 feet in width, stating that the width of such easements and temporary work space should be determined on a case by case basis dependent on the needs of each particular relocation and whether a road improvement is a material interference with the easement.  Reimbursement for any future relocation expenses will also be determined on a case by case basis. As a result of the decision by the 4th DCA affirming the monetary award of the judgment and the trial court’s November 7, 2012 issuance of a peremptory writ of mandamus, FDOT paid to FGT on November 16, 2012 the sum of $100 million, representing the amount of judgment plus interest through that date. The amounts received reduced FGTs’ property, plant and equipment costs. FGT previously filed a petition requesting the Supreme Court of Florida to exercise its discretionary jurisdiction and to reverse the portion of the 4th DCA decision overturning the trial court judgment specifically defining the width of FGTs’ easements and temporary work space. By order dated December 28, 2012, the Supreme Court of Florida denied that petition.
	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.
	The Texas case remains pending, and discovery is ongoing.
	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 deadline for the remaining defendants to file an answer or otherwise respond is March 1, 2013. Trial in this action is not currently set.
	CrossCountry, a “Principal” under the Citrus capital stock agreement, filed a complaint in the Delaware Court of Chancery against El Paso Citrus Holdings, Inc. (“EPCH”) and its parent El Paso Corp. (“El Paso”) seeking a declaratory judgment that the Citrus Acquisition does not, as El Paso contended, trigger any provisions of the capital stock agreement that would require Southern Union to provide El Paso a right of first refusal (ROFR) concerning Citrus. The complaint was filed by CrossCountry following an exchange of letters between El Paso and Southern Union regarding the terms of the capital stock agreement. Following the filing of the declaratory judgment action, El Paso filed a third-party complaint against Southern Union, ETE, and ETP alleging, among other things, breach the capital stock agreement. El Paso was not seeking to enjoin the closing of the Citrus Acquisition, but rather sought a rescission of the Citrus Acquisition after it was completed or, alternatively, damages. All parties have agreed the Citrus Acquisition did not trigger a ROFR and the courts granted El Paso’s dismissal of its claims for rescission or damages with prejudice on April 20, 2012.
	Litigation Related to Sunoco Merger
	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 is pending approval by the state court.
	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 December 31, 2012, Sunoco was a defendant in two lawsuits involving one state and Puerto Rico. These cases are venued in a multidistrict proceeding in a New York federal court. Both 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 the MBTE cases could have a significant impact on results of operations for any future period, but does not believe that the cases will have a material adverse effect on its consolidated financial position.
	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. Moreover, there can be no assurance that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, will not result in substantial costs and liabilities. We are unable to estimate any losses or range of losses that could result from such developments. 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.
	Our subsidiaries have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage and to limit the financial liability which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses. 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 subsidiaries’ liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future.
	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 CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require some of our subsidiaries 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 a 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 is required by October 2013.
	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 some of our subsidiaries to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if equipment is replaced or existing facilities are expanded 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 our subsidiaries might make in the future, but 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.
	On April 17, 2012 the EPA issued the Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. The standards revise the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants and new source performance standards for sulfur dioxide emissions from natural gas processing plants. The EPA also established standards for certain oil and gas operations not covered by the existing standards. In addition to the operations covered by the existing standards, the newly established standards regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels. ETP is reviewing the new standards to determine the impact on its operations.
	Our subsidiaries’ 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 our subsidiaries to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
	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 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 December 31, 2012, Sunoco had been named as a PRP at 35 identified or potentially identifiable as “Superfund” sites under federal and/or comparable state law. The Company 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.
	December 31,			31-Dec-11
	2012
Current	$	46		$	4
Non-current	166			10
Total environmental liabilities	$	212		$	14
During the year ended December 31, 2012 the Partnership had $12 million of expenditures related to environmental cleanup programs.

Price_Risk_Management_Assets_A

Price Risk Management Assets And Liabilities	12 Months Ended
	Dec. 31, 2012
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 segment.
	Investment in ETP
	ETP injects and hold natural gas in our Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.
	We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. We use financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	We are also exposed to commodity price risk on NGLs and residue gas we retain for fees in our midstream operations whereby the Company generally gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. We use derivative swap contracts to hedge forecasted sales of NGL equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
	Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, we also have trading activities related to power which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
	Derivatives are utilized in our midstream operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices.
	Prior to the deconsolidation of the Propane Business, we also used propane futures contracts to fix the purchase price related to certain fixed price sales contracts. Prior to the sale of our cylinder exchange business, we used propane futures contracts to secure the purchase price of our propane inventory for a percentage of the anticipated sales.
	The following table details ETP’s outstanding commodity-related derivatives:
		December 31, 2012				December 31, 2011
		Notional		Maturity		Notional			Maturity
		Volume				Volume
	Mark-to-Market Derivatives
	(Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX (1)	(30,980,000	)	2013-2014		(151,260,000	)		2012-2013
	Power (Megawatt):
	Forwards	19,650		2013		—			—
	Futures	(1,509,300	)	2013		—			—
	Options — Calls	1,656,400		2013		—			—
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	150,000		2013		(61,420,000	)		2012-2013
	Swing Swaps IFERC	(83,292,500	)	2013		92,370,000			2012-2013
	Fixed Swaps/Futures	27,077,500		2013		797,500			2012
	Forward Physical Contracts	11,689,855		2013-2014		(10,672,028	)		2012
	Options — Puts	—		2013		—			—
	NGLs (Bbls):
	Forwards/Swaps	(30,000	)	2013		—			—
	Refined Products (Bbls)	(666,000	)	2013		—			—
	Propane (Gallons):
	Forwards/Swaps	—		—		38,766,000			2012-2013
	Fair Value Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(18,655,000	)	2013		(28,752,500	)		2012
	Fixed Swaps/Futures	(44,272,500	)	2013		(45,822,500	)		2012
	Hedged Item — Inventory	44,272,500		2013		45,822,500			2012
	Cash Flow Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	(8,212,500	)	2013		—			—
	Options — Puts	—		—		3,600,000			2012
	Options — Calls	—		—		(3,600,000	)		2012
	NGLs (Bbls):
	Forwards/Swaps	(930,000	)	2013		—			—
	Refined Products (Bbls)	(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 losses of $6 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.
	Investment in 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.
	Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency GP have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency GP is responsible for delegation of transaction authority levels, and the Risk Management Committee of Regency GP is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency GP’s Risk Management Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.
	Regency’s Preferred Units (see Note 7) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and Regency’s call option. These embedded derivatives are accounted for using mark-to-market accounting. Regency does not expect the embedded derivatives to affect its cash flows.
	The following table details Regency’s outstanding commodity-related derivatives:
		31-Dec-12				31-Dec-11
		Notional		Maturity		Notional			Maturity
		Volume				Volume
	Mark-to-Market Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	8,395,000		2013-2014		—			—
Propane (Gallons):
Forwards/Swaps	3,318,000		2013		—			—
Natural Gas Liquids (Barrels):
Forwards/Swaps	243,000		2013-2014		—			—
Options — Puts	—		—		110,000			2012
WTI Crude Oil (Barrels):
Forwards/Swaps	356,000		2014		—			—
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	—		—		2,198,000			2012
Propane (Gallons):
Forwards/Swaps	—		—		11,802,000			2012-2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	—		—		533,000			2012-2013
WTI Crude Oil (Barrels):
Forwards/Swaps	—		—		350,000			2012-2014
As of December 31, 2011 all of the Regency’s commodity swap contracts were accounted for as cash flow hedges, and the Regency’s put options were accounted for on mark-to-market basis. On January 1, 2012, Regency, for accounting purposes, de-designated its swap contracts and will account for these contracts using the mark-to-market method of accounting. Regency has less than $1 million in net hedging gains in AOCI, the majority of which will be amortized to earnings over the next 12 months.
Interest Rate Risk
We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage our current interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. The following is a summary of interest rate swaps outstanding as of December 31, 2012, none of which are designated as hedges for accounting purposes:
					Notional Amount
					Outstanding
Entity		Term	Type(1)		December 31,				31-Dec-11
					2012
ETE		Mar-17	Pay a fixed rate of 1.25% and receive a floating rate		$	500			$	—
ETP		May 2012 (2)	Forward starting to pay a fixed rate of 2.59% and receive a floating rate		—				350
ETP		August 2012 (2)	Forward starting to pay a fixed rate of 3.51% and receive a floating rate		—				500
ETP		July 2013 (2)	Forward starting to pay a fixed rate of 4.02% and receive a floating rate		400				300
ETP		July 2014 (2)	Forward starting to pay a fixed rate of 4.26% and receive a floating rate		400				—
ETP		Jul-18	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		600				500
Regency		Apr-12	Pay a fixed rate of 1.325% and receive a floating rate		—				250
Southern Union		Nov-16	Pay a fixed rate of 2.913% and receive a floating rate		75				N/A
Southern Union		Nov-21	Pay a fixed rate of 3.746% and receive a floating rate		450				N/A
(1) Floating rates are based on 3-month LIBOR.
(2) These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.
As of December 31, 2012, Southern Union had no outstanding treasury rate locks; however, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in AOCI and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.
In connection with ETE’s offering of senior notes in September 2010, ETE terminated interest rate swaps with an aggregate notional amount of $1.5 billion and recognized in interest expense $66 million of realized losses on terminated interest rate swaps that had been accounted for as cash flow hedges. In addition to the $66 million of realized losses on hedged interest rate swaps, ETE also paid $102 million to terminate non-hedged interest rate swaps. The $102 million of realized losses on non-hedged interest rate swaps had previously been recognized in net income and therefore the termination of the non-hedged swaps did not impact earnings. The total cash paid to terminate interest rate swaps was $169 million, including realized losses on hedged and non-hedged swaps.
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 exposures associated with a single or multiple counterparties.
Our counterparties consist primarily of petrochemical companies and other industrial, small to major oil and gas producers, midstream and power generation companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on financial our position or results of operations as a result of counterparty nonperformance.
ETP utilizes master-netting agreements and have maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on 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. ETP had net deposits with counterparties of $41 million and $66 million as of December 31, 2012 and 2011, respectively.
Regency is exposed to credit risk from its derivative counterparties. Although Regency does not require collateral from these counterparties, Regency deals primarily with financial institutions when entering into financial derivatives, and enters into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.
Certain of Southern Union’s derivative instruments contain provisions that require Southern Union’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies. If Southern Union’s debt were to fall below investment grade, Southern Union would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require Southern Union to post collateral for certain of the derivative instruments. The aggregate fair value of Southern Union’s derivative instruments with credit-risk-related contingent features that are in a net liability position at December 31, 2012 was $4 million, all of which were included in the disposal group held for sale liabilities and December 31, 2012.
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 balance sheet overview of the Partnership’s derivative assets and liabilities as of December 31, 2012 and 2011:
	Fair Value of Derivative Instruments
	Asset Derivatives							Liability Derivatives
	2012			2011				2012				2011
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	8		$	77			$	(10	)		$	(1	)
Commodity derivatives	—			5				—				(10		)
	8			82				(10		)		(11		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	110		$	227			$	(116	)		$	(251	)
Commodity derivatives	40			1				(44		)		(5		)
Interest rate derivatives	55			36				(235		)		(118		)
Embedded derivatives in Regency Preferred Units	—			—				(25		)		(39		)
	205			264				(420		)		(413		)
Total derivatives	$	213		$	346			$	(430	)		$	(424	)
The commodity derivatives (margin deposits) are recorded in other current assets on our consolidated balance sheets. The remainder of the derivatives are recorded in price risk management assets or price risk management liabilities. As of December 31, 2012 commodity derivative assets of $1 million and commodity derivatives liabilities of $8 million were recorded as non-current assets held for sale and current liabilities held for sale in our consolidated balance sheet. In addition to the above derivatives, $7 million of option premiums included in price risk management liabilities as of December 31, 2012 will amortize in 2013.
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 for the periods presented:
	Change in Value Recognized in OCI
	on Derivatives (Effective Portion)
	Years Ended December 31,
	2012			2011				2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	8		$	6			$	50
Interest rate derivatives	—			—				(30		)
Total	$	8		$	6			$	20
		Location of	Amount of Gain/(Loss) Reclassified from
		Gain/(Loss) Reclassified	AOCI into Income (Effective Portion)
		from AOCI into Income	Years Ended December 31,
		(Effective Portion)	2012				2011				2010
Derivatives in cash flow hedging relationships:
Commodity derivatives		Cost of products sold	$	14			$	19			$	37
Interest rate derivatives		Interest expense, net	—				—				(87		)
Total			$	14			$	19			$	(50	)
		Location of Gain/(Loss)	Amount of Gain/(Loss) Recognized in Income
		Recognized in	Representing Hedge Ineffectiveness and
		Income on Derivatives	Amount Excluded from the Assessment of
			Effectiveness
			Years Ended December 31,
			2012				2011				2010
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives		Cost of products sold	$	54			$	34			$	16
Total			$	54			$	34			$	16
		Location of Gain/	Amount of Gain/(Loss) Recognized
		(Loss) Recognized in	in Income on Derivatives
		Income on Derivatives	Years Ended December 31,
			2012				2011				2010
Derivatives in cash flow hedging relationships:
Commodity derivatives – Trading		Cost of products sold	$	(7	)		$	(30	)		$	—
Commodity derivatives – Non-trading		Cost of products sold	26				9				4
Commodity derivatives – Non-trading		Deferred gas purchases	26				—				—
Interest rate derivatives		Losses on non-hedged interest rate derivatives	(19		)		(78		)		(52		)
Embedded derivatives		Other income (expense)	14				18				(8		)
Total			$	40			$	(81	)		$	(56	)

Retirement_Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2012
Compensation and Retirement Disclosure [Abstract]	'
Retirement Benefits	'
	RETIREMENT BENEFITS:
	Savings and Profit Sharing Plans
	We and our subsidiaries sponsor defined contribution savings plans which collectively cover virtually all employees, including those of ETP and Regency. Employer matching contributions are calculated using a formula based on employee contributions. We have made matching contributions of $11 million, $14 million and $10 million to the 401(k) savings plan for the years ended December 31, 2012, 2011 and 2010, respectively.
	Regency previously sponsored its own 401(k) plan. Effective January 1, 2011, Regency’s 401(k) plan merged with and into that of ETP. As a result of the Regency Transactions, Regency’s matching contributions that had not yet fully vested became fully vested effective immediately. Regency made matching contributions of $2 million to its own 401(k) savings plan for period from May 26, 2010 to December 31, 2010.
	Southern Union sponsors a defined contribution savings plan (Savings Plan) that is available to all employees.  Southern Union contributions to the Savings Plan during the period from Acquisition (March 26, 2012) to December 31, 2012 were $6 million.
	In addition, the Southern Union makes employer contributions to separate accounts, referred to as Retirement Power Accounts, within the defined contribution plan.  The contribution amounts are determined as a percentage of compensation and range from 3.5% to 12%.  Southern Union contributions are generally 100% vested after five years of continuous service.  Southern Union contributions to Retirement Power Accounts during the period from Acquisition (March 26, 2012) to December 31, 2012 were $2 million.
	Pension and Other Postretirement Benefit Plans
	Southern Union
	Southern Union has funded non-contributory defined benefit pension plans that cover substantially all employees of Southern Union’s distribution operations.  Normal retirement age is 65, but certain plan provisions allow for earlier retirement.  Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.
	The 2012 postretirement benefits expense for Southern Union reflects the impact of curtailment accounting as postretirement benefits for all active participants who did not meet certain criteria were eliminated.  The Company previously had postretirement health care and life insurance plans that covered substantially all Distribution and Transportation and Storage division employees, as well as all Corporate employees.  The health care plans generally provide for cost sharing between Southern Union and its retirees in the form of retiree contributions, deductibles, coinsurance, and a fixed cost cap on the amount Southern Union pays annually to provide future retiree health care coverage under certain of these plans.
	Sunoco
	Sunoco has both funded and unfunded noncontributory defined benefit pension plans (see “defined benefit plans”). Sunoco also has plans which provide health care benefits for substantially all of its current retirees (“postretirement benefit plans”). The postretirement benefit plans are unfunded and the costs are shared by Sunoco and its retirees. Prior to the Sunoco Merger on October 5, 2012, pension benefits under Sunoco’s defined benefit plans were frozen for most of the participants in these plans at which time Sunoco instituted a discretionary profit-sharing contribution on behalf of these employees in its defined contribution plan. Postretirement medical benefits were also phased down or eliminated for all employees retiring after July 1, 2010. Sunoco has established a trust for its postretirement benefit liabilities by making a tax-deductible contribution of approximately $200 million and restructuring the retiree medical plan to eliminate Sunoco’s liability beyond this funded amount. The retiree medical plan change eliminated substantially all of Sunoco’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.Obligations and Funded Status
	Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.  The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
		31-Dec-12
		Pension Benefits				Other Postretirement Benefits
	Change in benefit obligation:
	Benefit obligation at acquisition date	$	1,257			$	359
	Service cost	3				1
	Interest cost	15				3
	Amendments	—				17
	Benefits paid, net	(71		)		(8		)
	Curtailments	—				(80		)
	Actuarial (gain)/loss and other	(9		)		4
	Benefit obligation at end of period	$	1,195			$	296
	Change in plan assets:
	Fair value of plan assets at acquisition date	$	941			$	306
	Return on plan assets and other	22				5
	Employer contributions	14				9
	Benefits paid, net	(71		)		(8		)
	Fair value of plan assets at end of period	$	906			$	312
	Amount underfunded (overfunded) at end of period	$	289			$	(16	)
	Amounts recognized in the consolidated balance sheets consist of:
	Noncurrent assets	$	—			$	59
	Current liabilities	(15		)		(2		)
	Noncurrent liabilities	(274		)		(41		)
		$	(289	)		$	16
	Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
	Net actuarial gain	$	(1	)		$	(1	)
	Prior service cost	—				16
		$	(1	)		$	15
	The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
		Pension Benefits				Other Postretirement Benefits
	Projected benefit obligation	$	1,195			N/A
	Accumulated benefit obligation	1,179				$	225
	Fair value of plan assets	906				185
	Components of Net Periodic Benefit Cost
		December 31, 2012
		Pension Benefits				Other Postretirement Benefits
	Net Periodic Benefit Cost:
	Service cost	$	3			$	1
	Interest cost	15				3
	Expected return on plan assets	(21		)		(5		)
	Special termination benefits charge	2				—
	Curtailment recognition (1)	—				(15		)
		(1		)		(16		)
	Regulatory adjustment (2)	9				2
	Net periodic benefit cost	$	8			$	(14	)
	(1)	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.
	(2)	In its distribution operations, Southern Union recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.
	Assumptions
	The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
		31-Dec-12
		Pension Benefits			Other Postretirement Benefits
Discount rate	3.41	%		2.39	%
Rate of compensation increase	3.17	%		N/A
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
	December 31, 2012
	Pension Benefits			Other Postretirement Benefits
Discount rate	2.37	%		2.43	%
Expected return on assets:
Tax exempt accounts	7.63	%		7	%
Taxable accounts	N/A			4.5	%
Rate of compensation increase	3.02	%		N/A
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by Southern Union’s other postretirement benefit plans are shown in the table below:
		31-Dec-12
Health care cost trend rate assumed for next year		7.78	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)		5.32	%
Year that the rate reaches the ultimate trend rate		2018
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Southern Union plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its pension plan asset portfolio, Southern Union has targeted the following asset allocations: equity of 25% to 70%, fixed income of 15% to 35%, alternative assets of 10% to 35% and cash of 0% to 10%.  To achieve diversity within its other postretirement plan asset portfolio, Southern Union has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of 0% to 10%.
The investment strategy of Sunoco funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns, maintain a sufficient funded status of the plans and limit required contributions. Sunoco has targeted the following asset allocations: equity of 35%, fixed income of 55%, and private equity investments of 10%. Sunoco anticipates future shifts in targeted asset allocations from equity securities to fixed income securities if funding levels improve due to asset performance or Sunoco contributions.
The fair value of the pension plan assets by asset category at the dates indicated is as follows:
		Fair Value				Fair Value Measurements at
		as of				31-Dec-12
						Using Fair Value Hierarchy
		31-Dec-12				Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents		$	25			$	25	$	—	$	—
Mutual funds (1)		516				—		433		83
Fixed income securities		354				—		354		—
Multi-strategy hedge funds (2)		11				—		11		—
Total		$	906			$	25	$	798	$	83
(1)	Primarily comprised of approximately 36% equities, 54% fixed income securities, and 10% in other investments as of December 31, 2012.
(2)	Primarily includes hedge funds that invest in multiple strategies, including relative value, opportunistic/macro, long/short equities, merger arbitrage/event driven, credit, and short selling strategies, to generate long-term capital appreciation through a portfolio having a diversified risk profile with relatively low volatility and a low correlation with traditional equity and fixed-income markets.  These investments can generally be redeemed effective as of the last day of a calendar quarter at the net asset value per share of the investment with approximately 65 days prior written notice.
The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
		Fair Value				Fair Value Measurements at
		as of				31-Dec-12
						Using Fair Value Hierarchy
		31-Dec-12				Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents		$	7			$	7	$	—	$	—
Mutual funds (1)		147				126		21		—
Fixed income securities		158				—		158		—
Total		$	312			$	133	$	179	$	—
(1)	Primarily comprised of approximately 19% equities, 74% fixed income securities, 4% cash, and 3% in other investments as of December 31, 2012.
The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  See Note 2 for information related to the framework used to measure the fair value of its pension and other postretirement plan assets.
Contributions
We expect to contribute approximately $18 million to pension plans and approximately $8 million to other postretirement plans in 2013.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
Southern Union’s and Sunoco’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:
Years		Benefits				Other Postretirement Benefits		Other Postretirement Benefits
						(Gross, Before Medicare Part D)		(Medicare Part D Subsidy Receipts)
2013		$	254			$	38	$	1
2014		105				34		1
2015		98				33		1
2016		87				32		1
2017		82				30		1
2018 - 2021		328				107		4
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2012
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 the 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.
	Transactions between ETE’s subsidiaries and Enterprise were previously considered to be related party transactions due to Enterprise’s ownership of a portion of ETE’s limited partner interests.  During the years ended December 31, 2011 and 2010, subsidiaries of ETE recorded sales to Enterprise and $1.04 billion and $697 million, respectively, and purchases from Enterprise of $507 million and $444 million, respectively, all of which were related party transactions based on Enterprise’s interests in ETE at the time of the transactions.
	In addition, subsidiaries of ETE recorded sales with affiliates of $189 million during the year ended December 31, 2012.

Reportable_Segments

Reportable Segments	12 Months Ended
	Dec. 31, 2012
Reportable Segments [Abstract]	'
Reportable Segments	'
	REPORTABLE SEGMENTS:
	As a result of the Holdco Acquisition in April 2013, our reportable segments were re-evaluated and have been recast to reflect the following reportable 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.
	The segment information included below for the investment in Regency has been restated to reflect Regency’s retrospective consolidation of SUGS beginning March 26, 2012. Regency’s acquisition of SUGS was a transaction between entities under common control; therefore, Regency accounted for it similar to a pooling of interests. Accordingly, amounts reflected below for Regency have been adjusted to reflect Regency’s retrospective consolidation of SUGS.
	Revenues from intrastate transportation and storage operations are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from interstate transportation and storage operations are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from midstream operations are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from retail marketing operations are primarily reflected in retail marketing. Revenues from ETP’s investment in Sunoco Logistics are primarily reflected in crude sales. Revenues from our Investment in Regency are primarily reflected in natural gas sales, NGL sales, gathering, transportation and other fees.
	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.
	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.
		Years Ended December 31,
		2012			2011			2010
	Revenues:
	Investment in ETP:
	Revenues from external customers	$	15,671		$	6,761		$	5,843
	Intersegment revenues	31			38			—
		15,702			6,799			5,843
	Investment in Regency:
	Revenues from external customers	1,986			1,426			715
	Intersegment revenues	14			8			1
		2,000			1,434			716
	Adjustments and Eliminations:	(738		)	(43		)	(3		)
	Total revenues	$	16,964		$	8,190		$	6,556
	Costs of products sold:
	Investment in ETP	$	12,266		$	4,175		$	3,591
	Investment in Regency	1,387			1,013			504
	Adjustments and Eliminations	(565		)	(19		)	7
	Total costs of products sold	$	13,088		$	5,169		$	4,102
	Depreciation and amortization:
	Investment in ETP	656			405			317
	Investment in Regency	252			169			76
	Corporate and Other	14			12			13
	Adjustments and Eliminations	(51		)	—			—
	Total depreciation and amortization	$	871		$	586		$	406
		As of December 31,
		2012			2011			2010
	Equity in earnings of unconsolidated affiliates:
	Investment in ETP	$	142		$	26		$	12
	Investment in Regency	105			120			54
	Adjustments and Eliminations	(35		)	(29		)	(1		)
	Total equity in earnings of unconsolidated affiliates	$	212		$	117		$	65
		Years Ended December 31,
		2012			2011			2010
	Segment Adjusted EBITDA:
	Investment in ETP	$	2,744		$	1,781		$	1,541
	Investment in Regency	525			422			218
	Corporate and Other	(52		)	(29		)	(21		)
	Adjustments and Eliminations (1)	(112		)	(43		)	—
	Total	3,105			2,131			1,738
	Depreciation and amortization	(871		)	(586		)	(406		)
	Interest expense, net of interest capitalized	(1,018		)	(740		)	(625		)
	Bridge loan related fees	(62		)	—			—
	Gain on deconsolidation of Propane Business	1,057			—			—
	Losses on non-hedged interest rate derivatives	(19		)	(78		)	(52		)
	Non-cash unit-based compensation expense	(47		)	(42		)	(31		)
	Unrealized gains (losses) on commodity risk management activities	10			7			(110		)
	Losses on extinguishments of debt	(123		)	—			(16		)
	LIFO valuation reserve	(75		)	—			—
	Proportionate share of unconsolidated affiliates’ interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes	(435		)	(114		)	(71		)
	Adjusted EBITDA related to discontinued operations	(99		)	(23		)	(19		)
	Other, net	14			(7		)	(49		)
	Income from continuing operations before income tax expense	$	1,437		$	548		$	359
	As of December 31,
	2012			2011			2010
Total assets:
Investment in ETP	$	43,230		$	15,519		$	12,450
Investment in Regency	8,123			5,568			4,770
Corporate and Other	707			470			469
Adjustments and Eliminations	(3,156		)	(660		)	(11		)
Total	$	48,904		$	20,897		$	17,678
	Years Ended December 31,
	2012			2011			2010
Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
Investment in ETP (1)	$	3,057		$	2,922		$	1,470
Investment in Regency (2)	560			411			2,068
Adjustments and Eliminations	(124		)	—			—
Total	$	3,493		$	3,333		$	3,538
(1) The year ended December 31, 2011 includes $1.42 billion acquired in the LDH Acquisition.
(2) The year ended December 31, 2010 includes $1.55 billion acquired in the Regency Transactions.
	As of December 31,
	2012			2011			2010
Advances to and investments in affiliates:
Investment in ETP	$	3,502		$	201		$	9
Investment in Regency	2,214			1,925			1,351
Adjustments and Eliminations	(979		)	(629		)	—
Total	$	4,737		$	1,497		$	1,360

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Financial Data (Unaudited)	'
	QUARTERLY FINANCIAL DATA (UNAUDITED):
	Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year. For 2011, ETP’s propane operations were seasonal due to weather conditions in their service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Sales to commercial and industrial customers are less weather sensitive. ETP’s Energy Transfer Company (“ETC OLP”) business is also seasonal due to the operations of ET Fuel System and the HPL System. We expect margin related to the HPL System operations to be higher during the periods from November through March of each year and lower during the periods from April through October of each year due to the increased demand for natural gas during the cold weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
		Quarters Ended
		March 31		June 30		September 30			December 31		Total Year
	2012:00:00
	Revenues	$	1,669	$	1,875	$	2,107		$	11,313	$	16,964
	Gross margin	654		916		876			1,430		3,876
	Operating income	183		367		358			452		1,360
	Net income	961		75		(34		)	272		1,274
	Limited Partners’ interest in net income	166		53		35			48		302
	Basic net income per limited partner unit	$	0.73	$	0.19	$	0.13		$	0.17	$	1.13
	Diluted net income per limited partner unit	$	0.73	$	0.19	$	0.13		$	0.17	$	1.13
	2011:00:00
	Revenues	$	1,977	$	1,963	$	2,084		$	2,166	$	8,190
	Gross margin	778		703		736			804		3,021
	Operating income	363		263		272			339		1,237
	Net income	199		107		61			161		528
	Limited Partners’ interest in net income	88		66		69			86		309
	Basic net income per limited partner unit	$	0.4	$	0.3	$	0.31		$	0.38	$	1.39
	Diluted net income per limited partner unit	$	0.4	$	0.3	$	0.31		$	0.38	$	1.38

Supplemental_Financial_Stateme

Supplemental Financial Statement Information	12 Months Ended
	Dec. 31, 2012
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
		December 31,
		2012			2011
	ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents	$	9		$	18
	Accounts receivable from related companies	11			1
	Note receivable from affiliate	3			—
	Other current assets	—			1
	Total current assets	23			20
	ADVANCES TO AND INVESTMENTS IN AFFILIATES	6,094			2,226
	INTANGIBLE ASSETS, net	19			—
	GOODWILL	9			—
	OTHER NON-CURRENT ASSETS, net	222			50
	Total assets	$	6,367		$	2,296
	LIABILITIES AND PARTNERS’ CAPITAL
	CURRENT LIABILITIES:
	Accounts payable	$	1		$	—
	Accounts payable to related companies	15			12
	Interest payable	48			35
	Price risk management liabilities	5			—
	Accrued and other current liabilities	1			1
	Current maturities of long-term debt	4			—
	Total current liabilities	74			48
	LONG-TERM DEBT, less current maturities	3,840			1,872
	PREFERRED UNITS	331			323
	OTHER NON-CURRENT LIABILITIES	9			—
	COMMITMENTS AND CONTINGENCIES
	PARTNERS’ CAPITAL:
	General Partner	—			—
	Limited Partners – Common Unitholders (279,955,608 and 222,972,708 units authorized, issued and outstanding at December 31, 2012 and 2011, respectively)	2,125			52
	Accumulated other comprehensive income (loss)	(12		)	1
	Total partners’ capital	2,113			53
	Total liabilities and partners’ capital	$	6,367		$	2,296
	STATEMENTS OF OPERATIONS
		Years Ended December 31,
		2012			2011			2010
	SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(53	)	$	(30	)	$	(22	)
	OTHER INCOME (EXPENSE):
	Interest expense, net of interest capitalized	(235		)	(164		)	(168		)
	Bridge loan related fees	(62		)	—			—
	Equity in earnings of affiliates	666			509			456
	Losses on non-hedged interest rate derivatives	(15		)	—			(53		)
	Other, net	(4		)	(5		)	(20		)
	INCOME BEFORE INCOME TAXES	297			310			193
	Income tax benefit	(7		)	—			—
	NET INCOME	304			310			193
	GENERAL PARTNER’S INTEREST IN NET INCOME	2			1			1
	LIMITED PARTNERS’ INTEREST IN NET INCOME	$	302		$	309		$	192
	STATEMENTS OF CASH FLOWS
		Years Ended December 31,
		2012			2011			2010
	NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	555		$	469		$	317
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Cash paid for acquisitions	(1,113		)	—			—
	Contributions to affiliates	(487		)	—			—
	Note receivable from affiliate	(221		)	—			—
	Payments received on note receivable from affiliate	55			—			—
	MEP Transaction	—			—			3
	Net cash provided by (used in) investing activities	(1,766		)	—			3
	CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,108			92			1,858
Principal payments on debt	(162		)	(20		)	(1,632		)
Distributions to partners	(666		)	(526		)	(483		)
Debt issuance costs	(78		)	(24		)	(36		)
Net cash provided by (used in) financing activities	1,202			(478		)	(293		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(9		)	(9		)	27
CASH AND CASH EQUIVALENTS, beginning of period	18			27			—
CASH AND CASH EQUIVALENTS, end of period	$	9		$	18		$	27

Estimates_Significant_Accounti1

Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)	12 Months Ended
	Dec. 31, 2012
Accounting Policies [Abstract]	'
Equity and Cost Method Investments, Policy [Policy Text Block]	'
	Advances to and Investments in Affiliates
	Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment in which we have a 20% to 50% ownership and exercise significant influence over, but do not control the investee’s operating and financial policies.
Use of Estimates	'
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
	The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
	Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.
Revenue Recognition	'
	Revenue Recognition
	Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.
	Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
	Our intrastate transportation and storage and interstate transportation and storage operations’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
	Our intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from the midstream operations’ marketing activities, and from producers at the wellhead.
	In addition, our intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
	Results from the midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
	We also utilize other types of arrangements in our midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we 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, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
	NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer.
	We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
	Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
	Our retail marketing operations sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. In addition some of Sunoco’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
	Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas gathering, processing and transportation, (iii) contract compression services and (iv) contract treating services. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas at a price approximating the index price and NGLs to third parties. Regency generally reports revenue gross when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers.
Regulatory Accounting - Regulatory Assets and Liabilities	'
	Regulatory Accounting - Regulatory Assets and Liabilities
	Our interstate transportation and storage operations are subject to regulation by certain state and federal authorities and has accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
	Southern Union records regulatory assets with respect to its distribution operations.  We recorded regulatory assets with respect to Southern Union’s distribution operations, which have been classified as discontinued operations as of December 31, 2012. At December 31, 2012, we had $123 million of regulatory assets included in the consolidated balance sheet as non-current assets held for sale. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information	'
	Cash, Cash Equivalents and Supplemental Cash Flow Information
	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 which are subject to an insignificant risk of changes in value.
	We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
Accounts Receivable	'
	Accounts Receivable
	Our subsidiaries assess the credit risk of their customers. Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral). Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and specific identification.
Inventories	'
	Inventories
	Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.
Exchanges	'
	Exchanges
	Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.
Property, Plant and Equipment	'
	Property, Plant and Equipment
	Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
	We and our subsidiaries review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $128 million during the year ended December 31, 2012.
	Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an AFUDC is accrued. Interest is capitalized based on the current borrowing rate when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts - borrowed funds and equity funds.
Goodwill	'
	Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
Intangible Assets	'
	We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
	Intangible Assets
	Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our consolidated balance sheets the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Other Non-Current Assets, net	'
	Other Non-Current Assets, net
	Other non-current assets, net are stated at cost less accumulated amortization.
Asset Retirement Obligation	'
	Asset Retirement Obligation
	We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
	An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably determine the settlement dates.
	Except for the AROs of Southern Union, Sunoco Logistics and Sunoco discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2012 and 2011 because the settlement dates were indeterminable. Although a number of other onshore assets in Southern Union’s system are subject to agreements or regulations that give rise to an ARO upon Southern Union’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco has legal asset retirement obligations for several other assets at its refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
	Below is a schedule of AROs by entity recorded as other non-current liabilities in ETP’s consolidated balance sheet as of December 31, 2012:
	Southern Union	$	46
	Sunoco	53
	Sunoco Logistics	41
		$	140
	Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have has in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments
	The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
	We have marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units and embedded derivatives in the Preferred Units of a Subsidiary (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 marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. 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. The fair value of the Preferred Units was based predominantly on an income approach model and is also considered Level 3.
Shipping and Handling Costs	'
	Shipping and Handling Costs
	Shipping and handling costs related to fuel sold are included in cost of products sold. Shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and totaled $25 million, $40 million and $43 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Costs and Expenses	'
	Costs and Expenses
	Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
	We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income.
Issuances of Subsidiary Units	'
	Issuances of Subsidiary Units
	We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon ETP’s or Regency’s issuance of respective ETP or Regency Common Units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as
Income Taxes	'
Accounting for Derivative Instruments and Hedging Activities	'
	Accounting for Derivative Instruments and Hedging Activities
	For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.
	At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
	If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
	Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
	If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
	We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on non-hedged interest rate derivatives” in the consolidated statement
Allocation of Income (Loss)	'
	Allocation of Income
	For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see Note 8).

Operations_And_Organization_Ta

Operations And Organization (Tables)	12 Months Ended
	Dec. 31, 2012
Operations And Organization [Abstract]	'
Schedule Of Equity Interests	'
	At December 31, 2012, our equity interests in Regency and ETP consisted of:
		General Partner		Incentive		Limited
		Interest (as a %		Distribution		Partner Units
		of total		Rights
		partnership		(“IDRs”)
		interest)
	ETP	0.9	%	100	%	50,226,967
	Regency	1.6	%	100	%	26,266,791

Estimates_Significant_Accounti2

Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables)	12 Months Ended
	Dec. 31, 2012
Accounting Policies [Abstract]	'
Goodwill and Intangible Assets, Policy [Policy Text Block]	'
	Goodwill
	Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage and midstream operations, as of November 30 for the Southern Union reporting units and as of December 31 for all others, including all of Regency’s reporting units. No goodwill impairments were recorded for the periods presented in these consolidated financial statements.
Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities	'
	The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:
		Years Ended December 31,
		2012				2011			2010
	Accounts receivable	$	267			$	6		$	92
	Accounts receivable from related companies	(9		)		(24		)	(26		)
	Inventories	(258		)		51			15
	Exchanges receivable	14				1			1
	Other current assets	597				(51		)	33
	Other non-current assets, net	(129		)		7			6
	Accounts payable	(989		)		21			(67		)
	Accounts payable to related companies	92				6			(10		)
	Exchanges payable	—				2			(4		)
	Accrued and other current liabilities	(159		)		84			74
	Other non-current liabilities	26				—			—
	Price risk management assets and liabilities, net	(3		)		55			146
	Net change in operating assets and liabilities, net of effects of acquisitions, dispositions and deconsolidation	$	(551	)		$	158		$	260
Schedule Of Non-Cash Investing And Financing Activities	'
	Non-cash investing and financing activities and supplemental cash flow information were as follows:
		Years Ended December 31,
		2012				2011			2010
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	420			$	226		$	108
	Net gain from subsidiary common unit transactions	$	80			$	153		$	352
	AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	1,123			$	—		$	—
	NON-CASH FINANCING ACTIVITIES:
	Issuance of common units in connection with Southern Union Merger (see Note 3)	$	2,354			$	—		$	—
	Long-term debt assumed and non-compete agreement notes payable issued from acquisitions	$	6,658			$	4		$	1,243
	Subsidiary issuance of Common Units in connection with certain acquisitions	$	2,295			$	3		$	584
	SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest, net of interest capitalized	$	997			$	728		$	547
	Cash paid for income taxes	$	23			$	27		$	9
Schedule of Inventory	'
	Inventories consisted of the following:
		December 31,
		2012				2011
	Natural gas and NGLs, excluding propane	$	338			$	146
	Propane	—				87
	Crude oil	418				—
	Refined products	572				—
	Appliances, parts and fittings and other	194				95
	Total inventories	$	1,522			$	328
Other Current Assets	'
	Other current assets consisted of the following:
		December 31,
		2012				2011
	Deposits paid to vendors	$	41			$	66
	Prepaid and other	270				118
	Total other current assets	$	311			$	184
Property, Plant and Equipment	'
	Components and useful lives of property, plant and equipment were as follows:
		December 31,
		2012				2011
	Land and improvements	$	553			$	137
	Buildings and improvements (5 to 40 years)	587				279
	Pipelines and equipment (5 to 83 years)	19,505				11,359
	Natural gas and NGL storage facilities (5 to 46 years)	1,057				790
	Bulk storage, equipment and facilities (5 to 83 years)	1,745				977
	Tanks and other equipment (10 to 40 years)	1,194				644
	Retail equipment (3 to 99 years)	258				—
	Vehicles (3 to 25 years)	96				231
	Right of way (20 to 83 years)	2,134				793
	Furniture and fixtures (3 to 12 years)	50				48
	Linepack	118				59
	Pad gas	58				58
	Other (2 to 19 years)	1,060				234
	Construction work-in-process	1,973				921
		30,388				16,530
	Less - Accumulated depreciation	(2,104		)		(1,971		)
	Property, plant and equipment, net	$	28,284			$	14,559
Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense	'
	We recognized the following amounts of depreciation expense and capitalized interest expense for the periods presented:
		Years Ended December 31,
		2012				2011			2010
	Depreciation expense (1)	$	801			$	531		$	370
	Capitalized interest, excluding AFUDC	$	99			$	13		$	4
Schedule of Goodwill	'
	Changes in the carrying amount of goodwill were as follows:
		Balance, December 31, 2010				Goodwill acquired			Balance, December 31, 2011			Goodwill acquired			Disposal of Goodwill (1)			Balance, December 31, 2012
	ETP Intrastate Transportation and Storage	$	10			$	—		$	10		$	—		—			$	10
	ETP Interstate Transportation and Storage	99				—			99			1,785			—			1,884
	ETP Midstream	50				—			50			338			—			388
	ETP NGL Transportation and Services	—				432			432			—			—			432
	ETP Retail Marketing	—				—			—			1,272			—			1,272
	Investment in Sunoco Logistics	—				—			—			1,368			—			1,368
	Investment in Regency	790				—			790			—			—			790
	Corporate and Other	652				6			658			384			(752		)	290
	Total	$	1,601			$	438		$	2,039		$	5,147		$	(752	)	$	6,434
	(1) Includes goodwill deconsolidated or disposed of during the year ended December 31, 2012 and goodwill reclassified to non-current assets held for sale at December 31, 2012.
Components And Useful Lives Of Intangibles And Other Assets	'
	Components and useful lives of intangible assets were as follows:
		December 31, 2012							December 31, 2011
		Gross Carrying				Accumulated			Gross Carrying			Accumulated
		Amount				Amortization			Amount			Amortization
	Amortizable intangible assets:
	Customer relationships, contracts and agreements (3 to 46 years)	$	2,032			$	(150	)	$	1,059		$	(135	)
	Trade names (20 years)	66				(8		)	66			(5		)
	Noncompete agreements (3 to 15 years)	—				—			15			(8		)
	Patents (9 years)	48				(1		)	1			—
	Other (10 to 15 years)	4				(1		)	1			(1		)
	Total amortizable intangible assets	2,150				(160		)	1,142			(149		)
	Non-amortizable intangible assets:
	Trademarks	301				—			79			—
	Total intangible assets	$	2,451			$	(160	)	$	1,221		$	(149	)
Aggregate Amortization Expense Of Intangibles And Other Assets	'
	Aggregate amortization expense of intangibles assets was as follows:
		Years Ended December 31,
		2012				2011			2010
	Reported in depreciation and amortization	$	70			$	55		$	36
Estimated Aggregate Amortization Expense	'
	Estimated aggregate amortization expense of intangible assets for the next five years was as follows:
	Years Ending December 31:
	2013	$	116
	2014	115
	2015	115
	2016	115
	2017	115
Schedule of Other Non-Current Assets, net	'
	Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
		December 31,
		2012				2011
	Unamortized financing costs (3 to 30 years)	$	152			$	132
	Regulatory assets	93				89
	Deferred charges	140				—
	Other	148				28
	Total other non-current assets, net	$	533			$	249
Schedule of Asset Retirement Obligations [Table Text Block]	'
	Southern Union	$	46
	Sunoco	53
	Sunoco Logistics	41
		$	140
Accrued and Other Current Liabilities	'
	Accrued and other current liabilities consisted of the following:
		December 31,
		2012				2011
	Interest payable	$	334			$	204
	Customer advances and deposits	61				101
	Accrued capital expenditures	427				229
	Accrued wages and benefits	250				80
	Taxes payable other than income taxes	208				79
	Income taxes payable	41				15
	Deferred income taxes	130				—
	Other	303				56
	Total accrued and other current liabilities	$	1,754			$	764
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 December 31, 2012 and 2011 based on inputs used to derive their fair values:
		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	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	(8		)		(1		)	(7		)	—
	Total commodity derivatives	(168		)		(118		)	(50		)	—
	Total Liabilities	$	(759	)		$	(118	)	$	(285	)	$	(356	)
		Fair Value Measurements at
		December 31, 2011 Using
		Fair Value				Level 1			Level 2			Level 3
		Total
	Assets:
	Marketable securities (included in other current assets)	$	1			$	1		$	—		$	—
	Interest rate derivatives	36				—			36			—
	Commodity derivatives:
	Condensate — Forward Swaps	1				—			1			—
	Natural Gas:
	Basis Swaps IFERC/NYMEX	63				63			—			—
	Swing Swaps IFERC	15				2			13			—
	Fixed Swaps/Futures	219				215			4			—
	Options — Puts	6				—			6			—
	Forward Physical Swaps	1				—			1			—
	Total commodity derivatives	305				280			25			—
	Total Assets	$	342			$	281		$	61		$	—
	Liabilities:
	Interest rate derivatives	$	(117	)		$	—		$	(117	)	$	—
	Series A Convertible Preferred Units	(323		)		—			—			(323		)
Embedded derivatives in the Regency Preferred Units	(39		)		—			—			(39		)
Commodity derivatives:
Condensate — Forward Swaps	(2		)		—			(2		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(82		)		(82		)	—			—
Swing Swaps IFERC	(16		)		(3		)	(13		)	—
Fixed Swaps/Futures	(148		)		(148		)	—			—
Forward Physical Swaps	(1		)		—			(1		)	—
NGLs — Forward Swaps	(9		)		—			(9		)	—
Propane — Forward Swaps	(4		)		—			(4		)	—
Total commodity derivatives	(262		)		(233		)	(29		)	—
Total Liabilities	$	(741	)		$	(233	)	$	(146	)	$	(362	)
Unobservable Inputs of Fair Value Level 3 Liabilities [Table Text Block]	'
	The following table presents the material unobservable inputs used to estimate the fair value of the Preferred Units and the embedded derivatives in Regency’s Preferred Units:
		Unobservable Input		31-Dec-12
	Preferred Units	Assumed Yield		6.11	%
	Embedded derivatives in the Regency Preferred Units	Credit Spread		6.49	%
		Volatility		21.38	%
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 year ended December 31, 2012. There were no transfers between the fair value hierarchy levels during the years ended December 31, 2012 or 2011.
	Balance, December 31, 2011	$	(362	)
	Net unrealized gains included in other income (expense)	6
	Balance, December 31, 2012	$	(356	)

Acquisitions_and_Related_Trans1

Acquisitions and Related Transactions (Tables)	12 Months Ended
	Dec. 31, 2012
Acquisitions and Dispositions [Abstract]	'
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	'
Pro Forma Results Of Operations	'

Advances_to_and_Investments_in1

Advances to and Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2012
Investment In Affiliates [Abstract]	'
Schedule Of Aggregated Selected Balance Sheet And Income Statement Data For Our Unconsolidated Affiliates	'
	Summarized Financial Information
	The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis for all periods presented).
		December 31,
		2012		2011
	Current assets	$	945	$	893
	Property, plant and equipment, net	10,979		10,393
	Other assets	2,677		962
	Total assets	$	14,601	$	12,248
	Current liabilities	$	1,662	$	1,548
	Non-current liabilities	7,024		5,778
	Equity	5,915		4,922
	Total liabilities and equity	$	14,601	$	12,248
		Years Ended December 31,
		2012		2011		2010
	Revenue	$	4,492	$	3,784	$	3,287
	Operating income	863		928		716
	Net income	491		536		506

Net_Income_Per_Limited_Partner1

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2012
Earnings Per Share [Abstract]	'
Reconciliation Of Net Income (Loss) And Weighted Average Units	'
	A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
		Years Ended December 31,
		2012			2011			2010
	Income from continuing operations	$	1,383		$	531		$	345
	Less: Income from continuing operations attributable to noncontrolling interest	1,070			221			149
	Income from continuing operations, net of noncontrolling interest	313			310			196
	Less: General Partner’s interest in income from continuing operations	1			1			1
	Income from continuing operations available to Limited Partners	$	312		$	309		$	195
	Basic Income from Continuing Operations per Limited Partner Unit:
	Weighted average limited partner units	266,722,030			222,968,261			222,941,156
	Basic income from continuing operations per Limited Partner unit	$	1.17		$	1.39		$	0.87
	Basic loss from discontinued operations per Limited Partner unit	$	(0.04	)	$	—		$	(0.01	)
	Diluted Income from Continuing Operations per Limited Partner Unit:
	Income from continuing operations available to Limited Partners	$	312		$	309		$	195
	Dilutive effect of equity-based compensation of subsidiaries	(1		)	(1		)	—
	Diluted income from continuing operations available to Limited Partners	311			308			195
	Weighted average limited partner units	266,722,030			222,968,261			222,941,156
	Diluted income from continuing operations per Limited Partner unit	$	1.17		$	1.38		$	0.87
	Diluted loss from discontinued operations per Limited Partner unit	$	(0.04	)	$	—		$	(0.01	)

Debt_Obligations_Debt_Obligati

Debt Obligations Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2012
Debt Instrument [Line Items]	'
Schedule of debt obligations	'
	Our debt obligations consist of the following:
		December 31,
		2012			2011
	Parent Company Indebtedness:
	ETE Senior Notes, due October 15, 2020	$	1,800		$	1,800
	ETE Senior Secured Term Loan, due March 26, 2017	2,000			—
	ETE Senior Secured Revolving Credit Facility	60			72
	Other	19			1
	Unamortized premiums, discounts and fair value adjustments, net	(34		)	(1		)
		3,845			1,872
	Subsidiary Indebtedness:
	ETP Debt
	5.65% Senior Notes due August 1, 2012	—			400
	6.0% Senior Notes due July 1, 2013	350			350
	8.5% Senior Notes due April 15, 2014	292			350
	5.95% Senior Notes due February 1, 2015	750			750
	6.125% Senior Notes due February 15, 2017	400			400
	6.7% Senior Notes due July 1, 2018	600			600
	9.7% Senior Notes due March 15, 2019	400			600
	9.0% Senior Notes due April 15, 2019	450			650
	4.65% Senior Notes due June 1, 2021	800			800
	5.20% Senior Notes due February 1, 2022	1,000			—
	6.625% Senior Notes due October 15, 2036	400			400
	7.5% Senior Notes due July 1, 2038	550			550
	6.05% Senior Notes due June 1, 2041	700			700
	6.5% Senior Notes due February 1, 2042	1,000			—
	ETP $2.5 billion Revolving Credit Facility due October 27, 2016	1,395			314
	Other	—			81
	Unamortized premiums, discounts and fair value adjustments, net	(14		)	(2		)
		9,073			6,943
	Panhandle Debt
	6.05% Senior Notes due August 15, 2013	250			—
	6.2% Senior Notes due November 1, 2017	300			—
	7.0% Senior Notes due June 15, 2018	400			—
	8.125% Senior Notes due June 1, 2019	150			—
	7.0% Senior Notes due July 15, 2029	66			—
	Term Loan due February 23, 2015	455			—
	Unamortized premiums, discounts and fair value adjustments, net	136			—
		1,757			—
	Regency Debt
	9.375% Senior Notes due June 1, 2016	162			250
	6.875% Senior Notes due December 1, 2018	600			600
	6.5% Senior Notes due July 15, 2021	500			500
	5.5% Senior Notes due April 15, 2023	700			—
	Regency Revolving Credit Facility	192			332
	Unamortized premiums, discounts and fair value adjustments, net	3			5
		2,157			1,687
	Southern Union Debt
	7.6% Senior Notes due February 1, 2024	360			—
	8.25% Senior Notes due November 14, 2029	300			—
	7.2% Junior Subordinated Notes due November 1, 2066	600			—
	Southern Union Revolving Credit Facility	210			—
	Other	7			—
	Unamortized premiums, discounts and fair value adjustments, net	49			—
		1,526			—
	Sunoco Debt
	4.875% Senior Notes due October 15, 2014	250			—
	9.625% Senior Notes due April 15, 2015	250			—
	5.75% Senior Notes due January 15, 2017	400			—
	9.00% Debentures due November 1, 2024	65			—
	Other	25			—
	Unamortized premiums, discounts and fair value adjustments, net	104			—
		1,094			—
Sunoco Logistics Debt
8.75% Senior Notes due February 15, 2014	175			—
6.125% Senior Notes due May 15, 2016	175			—
5.50% Senior Notes due February 15, 2020	250			—
4.65% Senior Notes due February 15, 2022	300			—
6.85% Senior Notes due February 15, 2040	250			—
6.10% Senior Notes due February 15, 2042	300			—
Sunoco Logistics $200 million Revolving Credit Facility due August 21, 2013	26			—
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015	20			—
Sunoco Logistics $350 million Revolving Credit Facility due August 22, 2016	93			—
Unamortized premiums, discounts and fair value adjustments, net	143			—
	1,732			—
Transwestern Debt
5.39% Senior Notes due November 17, 2014	88			88
5.54% Senior Notes due November 17, 2016	125			125
5.64% Senior Notes due May 24, 2017	82			82
5.36% Senior Notes due December 9, 2020	175			175
5.89% Senior Notes due May 24, 2022	150			150
5.66% Senior Notes due December 9, 2024	175			175
6.16% Senior Notes due May 24, 2037	75			75
Unamortized premiums, discounts and fair value adjustments, net	(1		)	(1		)
	869			869
	22,053			11,371
Current maturities	(613		)	(424		)
	$	21,440		$	10,947
The f
Future maturities of long-term debt	'
	The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $386 million in unamortized premiums and fair value adjustments, net:
	2013	$	613
	2014	1,003
	2015	1,540
	2016	2,073
	2017	3,184
	Thereafter	13,254
	Total	$	21,667

Redeemable_Preferred_Units_Tab

Redeemable Preferred Units (Tables)	12 Months Ended
	Dec. 31, 2012
Preferred Units, Preferred Partners' Capital Accounts [Abstract]	'
Schedule of Redeemable Preferred Units	'
	time in accordance with Regency’s partnership agreement.
	The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:
		Regency	Amount
		Preferred
		Units
	Balance, December 31, 2011	4,371,586	$	71
	Accretion to redemption value	—	2
	Balance, December 31, 2012	4,371,586	$	73

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2012
Schedule Of Common Units Sold In Public Offering	'
	The following table summarizes ETP’s public offerings of ETP Common Units during the periods presented:
	Date		Number of			Price per ETP			Net Proceeds		Use of
			ETP Common			Unit					Proceeds
			Units (1)
	Jan-10		9,775,000			$	44.72		$	424	(2)(3)
	Aug-10		10,925,000			46.22			489		(2)(3)
	Apr-11		14,202,500			50.52			695		(3)
	Nov-11		15,237,500			44.67			660		(2)(3)
	Jul-12		15,525,000			44.57			671		(2)(3)
	(1)	Number of Common Units includes the exercise of the overallotment options by the underwriters.
	(2)	Proceeds were used to repay amounts outstanding under the ETP Credit Facility.
	(3)	Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.
	The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented:
	Date		Number of			Price per			Net Proceeds		Use of
			Regency Common			Regency Unit					Proceeds
			Units (1)
	Aug-10		17,537,500			$	23.8		$	400	(2)
	May-11		8,500,001			(4		)	204		(3)
	Oct-11		11,500,000			20.92			232		(2)
	Mar-12		12,650,000			24.47			297		(2)(3)
	(1)	Number of Common Units includes the exercise of the overallotment options by the underwriters.
	(2)	Proceeds were used to repay amounts outstanding under the Regency Credit Facility.
	(3)	Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.
	(4)	Regency Units were issued in a private placement.
Change In ETE Common Units	'
	The change in ETE Common Units during the years ended December 31, 2012, 2011 and 2010 was as follows:
		Years Ended December 31,
		2012			2011			2010
	Number of Common Units, beginning of period	222,972,708			222,941,172			222,898,248
	Issuance of restricted Common Units under long-term incentive plan	740			31,536			42,924
	Issuance of common units in connection with Southern Union Merger (See Note 3)	56,982,160			—			—
	Number of Common Units, end of period	279,955,608			222,972,708			222,941,172
Accumulated Other Comprehensive Income (Loss)	'
	The following table presents the components of AOCI, net of tax:
		December 31,
		2012				2011
	Net gains (losses) on commodity related hedges	$	(3	)		$	2
	Actuarial loss related to pensions and other postretirement benefits	(10		)		—
	Equity investments, net	(9		)		—
	Subtotal	(22		)		2
	Amounts attributable to noncontrolling interest	10				(1		)
	Total AOCI included in partners’ capital, net of tax	$	(12	)		$	1
Parent Company [Member]	'
Quarterly Distributions Of Available Cash	'
	Our distributions declared during the years ended December 31, 2012, 2011 and 2010 are summarized as follows:
	Quarter Ended		Record Date		Payment Date		Distribution per
							ETE Common Unit
	30-Sep-12		6-Nov-12		16-Nov-12		$	0.625
	30-Jun-12		6-Aug-12		17-Aug-12		0.625
	31-Mar-12		4-May-12		18-May-12		0.625
	31-Dec-11		7-Feb-12		17-Feb-12		0.625
	30-Sep-11		4-Nov-11		18-Nov-11		$	0.625
	30-Jun-11		5-Aug-11		19-Aug-11		0.625
	31-Mar-11		6-May-11		19-May-11		0.56
	31-Dec-10		7-Feb-11		18-Feb-11		0.54
	30-Sep-10		8-Nov-10		19-Nov-10		$	0.54
	30-Jun-10		9-Aug-10		19-Aug-10		0.54
	31-Mar-10		7-May-10		19-May-10		0.54
	31-Dec-09		8-Feb-10		19-Feb-10		0.54
ETP [Member]	'
Quarterly Distributions Of Available Cash	'
	ETP’s distributions declared during the periods presented below are summarized as follows:
	Quarter Ended		Record Date		Payment Date		Distribution per
							ETP Common Unit
	30-Sep-12		6-Nov-12		14-Nov-12		$	0.89375
	30-Jun-12		6-Aug-12		14-Aug-12		0.89375
	31-Mar-12		4-May-12		15-May-12		0.89375
	31-Dec-11		7-Feb-12		14-Feb-12		0.89375
	30-Sep-11		November 4, 2011		November 14, 2011		$	0.89375
	30-Jun-11		August 5, 2011		August 15, 2011		0.89375
	31-Mar-11		May 6, 2011		May 16, 2011		0.89375
	31-Dec-10		February 7, 2011		February 14, 2011		0.89375
	30-Sep-10		November 8, 2010		November 15, 2010		$	0.89375
	30-Jun-10		August 9, 2010		August 16, 2010		0.89375
	31-Mar-10		May 7, 2010		May 17, 2010		0.89375
	31-Dec-09		February 8, 2010		February 15, 2010		0.89375
Regency [Member]	'
Quarterly Distributions Of Available Cash	'
	Distributions paid by Regency since the date of acquisition are summarized as follows:
	Quarter Ended		Record Date		Payment Date		Distribution per
							Regency Common
							Unit
	September 30, 2012		6-Nov-12		14-Nov-12		$	0.46
	June 30, 2012		6-Aug-12		14-Aug-12		0.46
	March 31, 2012		7-May-12		14-May-12		0.46
	December 31, 2011		6-Feb-12		13-Feb-12		0.46
	30-Sep-11		7-Nov-11		14-Nov-11		$	0.455
	30-Jun-11		5-Aug-11		12-Aug-11		0.45
	31-Mar-11		6-May-11		13-May-11		0.445
	31-Dec-10		7-Feb-11		14-Feb-11		0.445
	30-Sep-10		November 5, 2010		November 12, 2010		$	0.445
	30-Jun-10		August 6, 2010		August 13, 2010		0.445

UnitBased_Compensation_Plans_U

Unit-Based Compensation Plans Unit-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2012
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]	'
Schedule Of ETP Awards Granted To Employees And Non-Employee Directos	'
		Number of		Weighted Average
		ETP Units		Grant-Date Fair
				Value Per ETP
				Unit
	Unvested awards as of December 31, 2011	2,563,709		$	46.37
	Awards granted	289,930		43.93
	Awards vested	(647,498	)	44.58
	Awards forfeited	(346,982	)	44.58
	Unvested awards as of December 31, 2012	1,859,159		46.95

Income_Taxes_Income_Taxes_Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2012
Federal and State Income Taxes [Abstract]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
	The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:
		Years Ended December 31,
		2012			2011			2010
	Current expense (benefit):
	Federal	$	(3	)	$	(1	)	$	1
	State	6			17			9
	Total	3			16			10
	Deferred expense:
	Federal	41			—			3
	State	10			1			1
	Total	51			1			4
	Total income tax expense from continuing operations	$	54		$	17		$	14
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	Historically, our effective tax rate differed from the statutory rate primarily due to partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union, Sunoco and Holdco transactions (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the year ended December 31, 2012 is a as follows:
		Holdco (1)			Other Corporate Subsidiaries (2)			Partnership (3)		Consolidated
	Income tax expense (benefit) at U.S. statutory rate of 35%	$	(1	)	$	(3	)	$	—	$	(4	)
	Increase (reduction) in income taxes resulting from:
	Nondeductible executive compensation	28			—			—		28
	State income taxes (net of federal income tax effects)	9			—			2		11
	Other	17			2			—		19
	Income Tax from continuing operations	$	53		$	(1	)	$	2	$	54
	(1)
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	'
		December 31,
		2012
	Net deferred income tax liability, beginning of year	$	(214	)
	Southern Union acquisition	(1,428		)
	Sunoco acquisition	(1,989		)
	Tax provision (including discontinued operations)	(62		)
	Other	(3		)
	Net deferred income tax liability	$	(3,696	)
		December 31,
		2012			2011
	Deferred tax assets:
	Net operating losses and alternative minimum tax credit	$	270		$	4
	Pension and other postretirement benefits	127			—
	Long term debt	117			—
	Other	290			4
	Total deferred income tax assets	804			8
	Valuation allowance	(94		)	(3		)
	Net deferred income tax assets	710			5
	Deferred income tax liabilities:
	Properties, plants and equipment	(2,026		)	(147		)
	Inventory	(516		)	—
	Investments in unconsolidated affiliates	(1,543		)	(72		)
	Trademarks	(192		)	—
	Other	(129		)	—
	Total deferred income tax liabilities	(4,406		)	(219		)
	Net deferred income tax liability	(3,696		)	(214		)
	Less: current portion of deferred income tax asset (liabilities)	(130		)	3
	Accumulated deferred income taxes	$	(3,566	)	$	(217	)
ScheduleOfUnrecognizedTaxBenefits [Table Text Block]	'
	The following table sets forth the changes in unrecognized tax benefits:
		Years Ended December 31,
		2012			2011			2010
	Balance at beginning of year	$	2		$	2		$	1
	Additions attributable to acquisitions	28			—			—
	Additions attributable to tax positions taken in the current year	—			1			—
	Additions attributable to tax positions taken in prior years	—			—			1
	Lapse of statute	(3		)	(1		)	—
	Balance at end of year	$	27		$	2		$	2

Regulatory_Matters_Commitments1

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)	12 Months Ended
	Dec. 31, 2012
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]	'
Environmental Exit Costs by Cost [Table Text Block]	'
	The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
		December 31,			31-Dec-11
		2012
	Current	$	46		$	4
	Non-current	166			10
	Total environmental liabilities	$	212		$	14
	During the year ended December 31, 2012 the Partnership had $12 million of expenditures related to environmental cleanup programs.
Schedule of Future Minimum Rental Payments for Operating Leases	'
	Future minimum lease commitments for such leases are:
	Years Ending December 31:
	2013	$	92
	2014	82
	2015	79
	2016	64
	2017	52
	Thereafter	462
	Future minimum lease commitments	831
	Less: Sublease rental income	(64		)
	Net future minimum lease commitments	$	767

Price_Risk_Management_Assets_A1

Price Risk Management Assets And Liabilities (Tables)	12 Months Ended
	Dec. 31, 2012
Interest Rate Swaps Outstanding	'
	The following is a summary of interest rate swaps outstanding as of December 31, 2012, none of which are designated as hedges for accounting purposes:
						Notional Amount
						Outstanding
	Entity		Term	Type(1)		December 31,				31-Dec-11
						2012
	ETE		Mar-17	Pay a fixed rate of 1.25% and receive a floating rate		$	500			$	—
	ETP		May 2012 (2)	Forward starting to pay a fixed rate of 2.59% and receive a floating rate		—				350
	ETP		August 2012 (2)	Forward starting to pay a fixed rate of 3.51% and receive a floating rate		—				500
	ETP		July 2013 (2)	Forward starting to pay a fixed rate of 4.02% and receive a floating rate		400				300
	ETP		July 2014 (2)	Forward starting to pay a fixed rate of 4.26% and receive a floating rate		400				—
	ETP		Jul-18	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		600				500
	Regency		Apr-12	Pay a fixed rate of 1.325% and receive a floating rate		—				250
	Southern Union		Nov-16	Pay a fixed rate of 2.913% and receive a floating rate		75				N/A
	Southern Union		Nov-21	Pay a fixed rate of 3.746% and receive a floating rate		450				N/A
	(1) Floating rates are based on 3-month LIBOR.
	(2) 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 balance sheet overview of the Partnership’s derivative assets and liabilities as of December 31, 2012 and 2011:
		Fair Value of Derivative Instruments
		Asset Derivatives							Liability Derivatives
		2012			2011				2012				2011
	Derivatives designated as hedging instruments:
	Commodity derivatives (margin deposits)	$	8		$	77			$	(10	)		$	(1	)
	Commodity derivatives	—			5				—				(10		)
		8			82				(10		)		(11		)
	Derivatives not designated as hedging instruments:
	Commodity derivatives (margin deposits)	$	110		$	227			$	(116	)		$	(251	)
	Commodity derivatives	40			1				(44		)		(5		)
	Interest rate derivatives	55			36				(235		)		(118		)
	Embedded derivatives in Regency Preferred Units	—			—				(25		)		(39		)
		205			264				(420		)		(413		)
	Total derivatives	$	213		$	346			$	(430	)		$	(424	)
Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives	'
	The following tables summarize the amounts recognized with respect to our derivative financial instruments for the periods presented:
		Change in Value Recognized in OCI
		on Derivatives (Effective Portion)
		Years Ended December 31,
		2012			2011				2010
	Derivatives in cash flow hedging relationships:
	Commodity derivatives	$	8		$	6			$	50
	Interest rate derivatives	—			—				(30		)
	Total	$	8		$	6			$	20
Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized	'
			Location of	Amount of Gain/(Loss) Reclassified from
			Gain/(Loss) Reclassified	AOCI into Income (Effective Portion)
			from AOCI into Income	Years Ended December 31,
			(Effective Portion)	2012				2011				2010
	Derivatives in cash flow hedging relationships:
	Commodity derivatives		Cost of products sold	$	14			$	19			$	37
	Interest rate derivatives		Interest expense, net	—				—				(87		)
	Total			$	14			$	19			$	(50	)
			Location of Gain/(Loss)	Amount of Gain/(Loss) Recognized in Income
			Recognized in	Representing Hedge Ineffectiveness and
			Income on Derivatives	Amount Excluded from the Assessment of
				Effectiveness
				Years Ended December 31,
				2012				2011				2010
	Derivatives in fair value hedging relationships (including hedged item):
	Commodity derivatives		Cost of products sold	$	54			$	34			$	16
	Total			$	54			$	34			$	16
			Location of Gain/	Amount of Gain/(Loss) Recognized
			(Loss) Recognized in	in Income on Derivatives
			Income on Derivatives	Years Ended December 31,
				2012				2011				2010
	Derivatives in cash flow hedging relationships:
	Commodity derivatives – Trading		Cost of products sold	$	(7	)		$	(30	)		$	—
	Commodity derivatives – Non-trading		Cost of products sold	26				9				4
	Commodity derivatives – Non-trading		Deferred gas purchases	26				—				—
	Interest rate derivatives		Losses on non-hedged interest rate derivatives	(19		)		(78		)		(52		)
	Embedded derivatives		Other income (expense)	14				18				(8		)
	Total			$	40			$	(81	)		$	(56	)
ETP [Member]	'
Outstanding Commodity-Related Derivatives	'
	The following table details ETP’s outstanding commodity-related derivatives:
		December 31, 2012				December 31, 2011
		Notional		Maturity		Notional			Maturity
		Volume				Volume
	Mark-to-Market Derivatives
	(Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX (1)	(30,980,000	)	2013-2014		(151,260,000	)		2012-2013
	Power (Megawatt):
	Forwards	19,650		2013		—			—
	Futures	(1,509,300	)	2013		—			—
	Options — Calls	1,656,400		2013		—			—
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	150,000		2013		(61,420,000	)		2012-2013
	Swing Swaps IFERC	(83,292,500	)	2013		92,370,000			2012-2013
	Fixed Swaps/Futures	27,077,500		2013		797,500			2012
	Forward Physical Contracts	11,689,855		2013-2014		(10,672,028	)		2012
	Options — Puts	—		2013		—			—
	NGLs (Bbls):
	Forwards/Swaps	(30,000	)	2013		—			—
	Refined Products (Bbls)	(666,000	)	2013		—			—
	Propane (Gallons):
	Forwards/Swaps	—		—		38,766,000			2012-2013
	Fair Value Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Basis Swaps IFERC/NYMEX	(18,655,000	)	2013		(28,752,500	)		2012
	Fixed Swaps/Futures	(44,272,500	)	2013		(45,822,500	)		2012
	Hedged Item — Inventory	44,272,500		2013		45,822,500			2012
	Cash Flow Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	(8,212,500	)	2013		—			—
	Options — Puts	—		—		3,600,000			2012
	Options — Calls	—		—		(3,600,000	)		2012
	NGLs (Bbls):
	Forwards/Swaps	(930,000	)	2013		—			—
	Refined Products (Bbls)	(98,000	)	2013		—			—
Regency [Member]	'
Outstanding Commodity-Related Derivatives	'
	The following table details Regency’s outstanding commodity-related derivatives:
		31-Dec-12				31-Dec-11
		Notional		Maturity		Notional			Maturity
		Volume				Volume
	Mark-to-Market Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	8,395,000		2013-2014		—			—
	Propane (Gallons):
	Forwards/Swaps	3,318,000		2013		—			—
	Natural Gas Liquids (Barrels):
	Forwards/Swaps	243,000		2013-2014		—			—
	Options — Puts	—		—		110,000			2012
	WTI Crude Oil (Barrels):
	Forwards/Swaps	356,000		2014		—			—
	Cash Flow Hedging Derivatives
	(Non-Trading)
	Natural Gas (MMBtu):
	Fixed Swaps/Futures	—		—		2,198,000			2012
	Propane (Gallons):
	Forwards/Swaps	—		—		11,802,000			2012-2013
	Natural Gas Liquids (Barrels):
	Forwards/Swaps	—		—		533,000			2012-2013
	WTI Crude Oil (Barrels):
	Forwards/Swaps	—		—		350,000			2012-2014

Retirement_Benefits_Retirement

Retirement Benefits Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2012
Compensation and Retirement Disclosure [Abstract]	'
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	'
	Obligations and Funded Status
	Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.  The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
		31-Dec-12
		Pension Benefits				Other Postretirement Benefits
	Change in benefit obligation:
	Benefit obligation at acquisition date	$	1,257			$	359
	Service cost	3				1
	Interest cost	15				3
	Amendments	—				17
	Benefits paid, net	(71		)		(8		)
	Curtailments	—				(80		)
	Actuarial (gain)/loss and other	(9		)		4
	Benefit obligation at end of period	$	1,195			$	296
	Change in plan assets:
	Fair value of plan assets at acquisition date	$	941			$	306
	Return on plan assets and other	22				5
	Employer contributions	14				9
	Benefits paid, net	(71		)		(8		)
	Fair value of plan assets at end of period	$	906			$	312
	Amount underfunded (overfunded) at end of period	$	289			$	(16	)
	Amounts recognized in the consolidated balance sheets consist of:
	Noncurrent assets	$	—			$	59
	Current liabilities	(15		)		(2		)
	Noncurrent liabilities	(274		)		(41		)
		$	(289	)		$	16
	Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
	Net actuarial gain	$	(1	)		$	(1	)
	Prior service cost	—				16
		$	(1	)		$	15
Schedule of Accumulated and Projected Benefit Obligations [Table Text Block]	'
	The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
		Pension Benefits				Other Postretirement Benefits
	Projected benefit obligation	$	1,195			N/A
	Accumulated benefit obligation	1,179				$	225
	Fair value of plan assets	906				185
Schedule of Benefit Obligations Assumptions [Table Text Block]	'
	Assumptions
	The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
		31-Dec-12
		Pension Benefits			Other Postretirement Benefits
	Discount rate	3.41	%		2.39	%
	Rate of compensation increase	3.17	%		N/A
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	'
	The assumed health care cost trend rates used to measure the expected cost of benefits covered by Southern Union’s other postretirement benefit plans are shown in the table below:
			31-Dec-12
	Health care cost trend rate assumed for next year		7.78	%
	Rate to which the cost trend is assumed to decline (the ultimate trend rate)		5.32	%
	Year that the rate reaches the ultimate trend rate		2018
Schedule of Health Care Cost Trend Rates [Table Text Block]	'
	.
Fair Value of Plan Assets [Table Text Block]	'
	The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
			Fair Value				Fair Value Measurements at
			as of				31-Dec-12
							Using Fair Value Hierarchy
			31-Dec-12				Level 1		Level 2		Level 3
	Asset Category:
	Cash and Cash Equivalents		$	7			$	7	$	—	$	—
	Mutual funds (1)		147				126		21		—
	Fixed income securities		158				—		158		—
	Total		$	312			$	133	$	179	$	—
	(1)	Primarily comprised of approximately 19% equities, 74% fixed income securities, 4% cash, and 3% in other investments as of December 31, 2012.
	The fair value of the pension plan assets by asset category at the dates indicated is as follows:
			Fair Value				Fair Value Measurements at
			as of				31-Dec-12
							Using Fair Value Hierarchy
			31-Dec-12				Level 1		Level 2		Level 3
	Asset Category:
	Cash and cash equivalents		$	25			$	25	$	—	$	—
	Mutual funds (1)		516				—		433		83
	Fixed income securities		354				—		354		—
	Multi-strategy hedge funds (2)		11				—		11		—
	Total		$	906			$	25	$	798	$	83
	(1)	Primarily comprised of approximately 36% equities, 54% fixed income securities, and 10% in other investments as of December 31, 2012.
	(2)	Primarily includes hedge funds that invest in multiple strategies, including relative value, opportunistic/macro, long/short equities, merger arbitrage/event driven, credit, and short selling strategies, to generate long-term capital appreciation through a portfolio having a diversified risk profile with relatively low volatility and a low correlation with traditional equity and fixed-income markets.  These investments can generally be redeemed effective as of the last day of a calendar quarter at the net asset value per share of the investment with approximately 65 days prior written notice.
Schedule of Expected Benefit Payments [Table Text Block]	'
	Benefit Payments
	Southern Union’s and Sunoco’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:
	Years		Benefits				Other Postretirement Benefits		Other Postretirement Benefits
							(Gross, Before Medicare Part D)		(Medicare Part D Subsidy Receipts)
	2013		$	254			$	38	$	1
	2014		105				34		1
	2015		98				33		1
	2016		87				32		1
	2017		82				30		1
	2018 - 2021		328				107		4

Reportable_Segments_Tables

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2012
Operating Segments [Member]	'
Financial Information By Segment	'
		Years Ended December 31,
		2012			2011			2010
	Revenues:
	Investment in ETP:
	Revenues from external customers	$	15,671		$	6,761		$	5,843
	Intersegment revenues	31			38			—
		15,702			6,799			5,843
	Investment in Regency:
	Revenues from external customers	1,986			1,426			715
	Intersegment revenues	14			8			1
		2,000			1,434			716
	Adjustments and Eliminations:	(738		)	(43		)	(3		)
	Total revenues	$	16,964		$	8,190		$	6,556
	Costs of products sold:
	Investment in ETP	$	12,266		$	4,175		$	3,591
	Investment in Regency	1,387			1,013			504
	Adjustments and Eliminations	(565		)	(19		)	7
	Total costs of products sold	$	13,088		$	5,169		$	4,102
	Depreciation and amortization:
	Investment in ETP	656			405			317
	Investment in Regency	252			169			76
	Corporate and Other	14			12			13
	Adjustments and Eliminations	(51		)	—			—
	Total depreciation and amortization	$	871		$	586		$	406
		As of December 31,
		2012			2011			2010
	Equity in earnings of unconsolidated affiliates:
	Investment in ETP	$	142		$	26		$	12
	Investment in Regency	105			120			54
	Adjustments and Eliminations	(35		)	(29		)	(1		)
	Total equity in earnings of unconsolidated affiliates	$	212		$	117		$	65
		Years Ended December 31,
		2012			2011			2010
	Segment Adjusted EBITDA:
	Investment in ETP	$	2,744		$	1,781		$	1,541
	Investment in Regency	525			422			218
	Corporate and Other	(52		)	(29		)	(21		)
	Adjustments and Eliminations (1)	(112		)	(43		)	—
	Total	3,105			2,131			1,738
	Depreciation and amortization	(871		)	(586		)	(406		)
	Interest expense, net of interest capitalized	(1,018		)	(740		)	(625		)
	Bridge loan related fees	(62		)	—			—
	Gain on deconsolidation of Propane Business	1,057			—			—
	Losses on non-hedged interest rate derivatives	(19		)	(78		)	(52		)
	Non-cash unit-based compensation expense	(47		)	(42		)	(31		)
	Unrealized gains (losses) on commodity risk management activities	10			7			(110		)
	Losses on extinguishments of debt	(123		)	—			(16		)
	LIFO valuation reserve	(75		)	—			—
	Proportionate share of unconsolidated affiliates’ interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes	(435		)	(114		)	(71		)
	Adjusted EBITDA related to discontinued operations	(99		)	(23		)	(19		)
	Other, net	14			(7		)	(49		)
	Income from continuing operations before income tax expense	$	1,437		$	548		$	359
		As of December 31,
		2012			2011			2010
	Total assets:
	Investment in ETP	$	43,230		$	15,519		$	12,450
	Investment in Regency	8,123			5,568			4,770
	Corporate and Other	707			470			469
	Adjustments and Eliminations	(3,156		)	(660		)	(11		)
	Total	$	48,904		$	20,897		$	17,678
		Years Ended December 31,
		2012			2011			2010
	Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
Investment in ETP (1)	$	3,057		$	2,922		$	1,470
Investment in Regency (2)	560			411			2,068
Adjustments and Eliminations	(124		)	—			—
Total	$	3,493		$	3,333		$	3,538
Assets Segments [Member]	'
Financial Information By Segment	'
		As of December 31,
		2012			2011			2010
	Total assets:
	Investment in ETP	$	43,230		$	15,519		$	12,450
	Investment in Regency	8,123			5,568			4,770
	Corporate and Other	707			470			469
	Adjustments and Eliminations	(3,156		)	(660		)	(11		)
	Total	$	48,904		$	20,897		$	17,678
Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments [Member]	'
Financial Information By Segment	'
		Years Ended December 31,
		2012			2011			2010
	Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
	Investment in ETP (1)	$	3,057		$	2,922		$	1,470
	Investment in Regency (2)	560			411			2,068
	Adjustments and Eliminations	(124		)	—			—
	Total	$	3,493		$	3,333		$	3,538
	(1) The year ended December 31, 2011 includes $1.42 billion acquired in the LDH Acquisition.
	(2) The year ended December 31, 2010 includes $1.55 billion acquired in the Regency Transactions.
Advances To And Investments In Affiliates Segments [Member]	'
Financial Information By Segment	'
		As of December 31,
		2012			2011			2010
	Advances to and investments in affiliates:
	Investment in ETP	$	3,502		$	201		$	9
	Investment in Regency	2,214			1,925			1,351
	Adjustments and Eliminations	(979		)	(629		)	—
	Total	$	4,737		$	1,497		$	1,360

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]	'
Schedule of Quarterly Financial Information	'
	industry, and other issues.
		Quarters Ended
		March 31		June 30		September 30			December 31		Total Year
	2012:00:00
	Revenues	$	1,669	$	1,875	$	2,107		$	11,313	$	16,964
	Gross margin	654		916		876			1,430		3,876
	Operating income	183		367		358			452		1,360
	Net income	961		75		(34		)	272		1,274
	Limited Partners’ interest in net income	166		53		35			48		302
	Basic net income per limited partner unit	$	0.73	$	0.19	$	0.13		$	0.17	$	1.13
	Diluted net income per limited partner unit	$	0.73	$	0.19	$	0.13		$	0.17	$	1.13
	2011:00:00
	Revenues	$	1,977	$	1,963	$	2,084		$	2,166	$	8,190
	Gross margin	778		703		736			804		3,021
	Operating income	363		263		272			339		1,237
	Net income	199		107		61			161		528
	Limited Partners’ interest in net income	88		66		69			86		309
	Basic net income per limited partner unit	$	0.4	$	0.3	$	0.31		$	0.38	$	1.39
	Diluted net income per limited partner unit	$	0.4	$	0.3	$	0.31		$	0.38	$	1.38

Supplemental_Financial_Stateme1

Supplemental Financial Statement Information (Tables)	12 Months Ended
	Dec. 31, 2012
Schedule Of Statements Of Cash Flows	'
	Non-cash investing and financing activities and supplemental cash flow information were as follows:
		Years Ended December 31,
		2012			2011			2010
	NON-CASH INVESTING ACTIVITIES:
	Accrued capital expenditures	$	420		$	226		$	108
	Net gain from subsidiary common unit transactions	$	80		$	153		$	352
	AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	1,123		$	—		$	—
	NON-CASH FINANCING ACTIVITIES:
	Issuance of common units in connection with Southern Union Merger (see Note 3)	$	2,354		$	—		$	—
	Long-term debt assumed and non-compete agreement notes payable issued from acquisitions	$	6,658		$	4		$	1,243
	Subsidiary issuance of Common Units in connection with certain acquisitions	$	2,295		$	3		$	584
	SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest, net of interest capitalized	$	997		$	728		$	547
	Cash paid for income taxes	$	23		$	27		$	9
Parent Company [Member]	'
Schedule Of Balance Sheets	'
	BALANCE SHEETS
		December 31,
		2012			2011
	ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents	$	9		$	18
	Accounts receivable from related companies	11			1
	Note receivable from affiliate	3			—
	Other current assets	—			1
	Total current assets	23			20
	ADVANCES TO AND INVESTMENTS IN AFFILIATES	6,094			2,226
	INTANGIBLE ASSETS, net	19			—
	GOODWILL	9			—
	OTHER NON-CURRENT ASSETS, net	222			50
	Total assets	$	6,367		$	2,296
	LIABILITIES AND PARTNERS’ CAPITAL
	CURRENT LIABILITIES:
	Accounts payable	$	1		$	—
	Accounts payable to related companies	15			12
	Interest payable	48			35
	Price risk management liabilities	5			—
	Accrued and other current liabilities	1			1
	Current maturities of long-term debt	4			—
	Total current liabilities	74			48
	LONG-TERM DEBT, less current maturities	3,840			1,872
	PREFERRED UNITS	331			323
	OTHER NON-CURRENT LIABILITIES	9			—
	COMMITMENTS AND CONTINGENCIES
	PARTNERS’ CAPITAL:
	General Partner	—			—
	Limited Partners – Common Unitholders (279,955,608 and 222,972,708 units authorized, issued and outstanding at December 31, 2012 and 2011, respectively)	2,125			52
	Accumulated other comprehensive income (loss)	(12		)	1
	Total partners’ capital	2,113			53
	Total liabilities and partners’ capital	$	6,367		$	2,296
Schedule Of Statements Of Operations	'
	STATEMENTS OF OPERATIONS
		Years Ended December 31,
		2012			2011			2010
	SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(53	)	$	(30	)	$	(22	)
	OTHER INCOME (EXPENSE):
	Interest expense, net of interest capitalized	(235		)	(164		)	(168		)
	Bridge loan related fees	(62		)	—			—
	Equity in earnings of affiliates	666			509			456
	Losses on non-hedged interest rate derivatives	(15		)	—			(53		)
	Other, net	(4		)	(5		)	(20		)
	INCOME BEFORE INCOME TAXES	297			310			193
	Income tax benefit	(7		)	—			—
	NET INCOME	304			310			193
	GENERAL PARTNER’S INTEREST IN NET INCOME	2			1			1
	LIMITED PARTNERS’ INTEREST IN NET INCOME	$	302		$	309		$	192
Schedule Of Statements Of Cash Flows	'
	STATEMENTS OF CASH FLOWS
		Years Ended December 31,
		2012			2011			2010
	NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	555		$	469		$	317
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Cash paid for acquisitions	(1,113		)	—			—
	Contributions to affiliates	(487		)	—			—
	Note receivable from affiliate	(221		)	—			—
	Payments received on note receivable from affiliate	55			—			—
	MEP Transaction	—			—			3
	Net cash provided by (used in) investing activities	(1,766		)	—			3
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from borrowings	2,108			92			1,858
	Principal payments on debt	(162		)	(20		)	(1,632		)
	Distributions to partners	(666		)	(526		)	(483		)
	Debt issuance costs	(78		)	(24		)	(36		)
	Net cash provided by (used in) financing activities	1,202			(478		)	(293		)
	INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(9		)	(9		)	27
	CASH AND CASH EQUIVALENTS, beginning of period	18			27			—
	CASH AND CASH EQUIVALENTS, end of period	$	9		$	18		$	27

Operations_And_Organization_Na

Operations And Organization (Narrative) (Details) (USD $)

Dec. 31, 2012

Oct. 05, 2012

25-May-10

Dec. 31, 2012

25-May-10

Dec. 31, 2012

Sep. 30, 2011

Dec. 31, 2012

Oct. 05, 2012

Dec. 31, 2012

Dec. 31, 2012

Oct. 05, 2012

Jan. 12, 2012

Dec. 31, 2012

Sep. 30, 2011

Dec. 31, 2012

Mar. 25, 2012

Dec. 31, 2010

Dec. 31, 2012

Mar. 25, 2012

Mar. 25, 2012

Dec. 31, 2011

Oct. 31, 2012

In Millions, except Share data, unless otherwise specified

FEP [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Lone Star L.L.C. [Member]

Parent Company [Member]

Citrus [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETE [Member]

SUG Merger [Member]

SUG Merger [Member]

Citrus Merger [Member]

Citrus Merger [Member]

Units Acquired for Equity [Member]

Units Acquired for Equity [Member]

Canyon [Member]

Lone Star L.L.C. [Member]

Lone Star L.L.C. [Member]

Lone Star L.L.C. [Member]

Lone Star L.L.C. [Member]

SUG Merger [Member]

SUG Merger [Member]

Business Combination, Consideration Transferred

$1,980

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$207

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

'

'

'

50.00%

'

'

'

70.00%

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity interest in Holdco

'

'

'

'

'

'

'

'

60.00%

'

40.00%

40.00%

'

'

'

60.00%

'

'

'

'

'

'

'

Business Acquisition, Cost of Acquired Entity, Cash Paid

'

'

$305

'

'

$592.70

'

'

'

'

'

'

'

$1,380

'

'

$3,010

'

$1,900

$1,900

'

'

'

Interest ownership

'

'

'

'

'

'

'

30.00%

'

50.00%

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

Subsidiary Interest in Joint Venture

'

'

'

'

'

30.00%

30.00%

'

'

'

'

'

'

70.00%

70.00%

'

'

'

'

'

'

'

'

Business Acquisition Units Acquired

'

'

'

'

26,300,000

'

'

'

'

'

'

'

30,000,000

'

'

'

'

0

'

'

56,982,160

0

'

Percent of total equity ownership of a subsidiary

'

32.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operations_And_Organization_Sc

Operations And Organization (Schedule Of Equity Interests (Details)	Oct. 05, 2012	Dec. 31, 2012	Dec. 31, 2012
		ETP [Member]	Regency [Member]
Incentive Distribution Rights	100.00%	100.00%	100.00%
Limited Partner Units	'	50,226,967	26,266,791
General Partner Interest	2.00%	0.90%	1.60%

Estimates_Significant_Accounti3

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policies [Abstract]	'	'	'
Shipping and handling costs	$25	$40	$43

Estimates_Significant_Accounti4

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policies [Abstract]	'	'	'
Accounts receivable	$267	$6	$92
Accounts receivable from related companies	-9	-24	-26
Inventories	-258	51	15
Exchanges receivable	14	1	1
Other current assets	597	-51	33
Other non-current assets, net	-129	7	6
Accounts payable	-989	21	-67
Accounts payable to related companies	92	6	-10
Exchanges payable	0	2	-4
Accrued and other current liabilities	-159	84	74
Other non-current liabilities	26	0	0
Price risk management assets and liabilities, net	-3	55	146
Net change in operating assets and liabilities, net of effects of acquisitions, dispositions and deconsolidation	($551)	$158	$260

Estimates_Significant_Accounti5

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule Of Non-Cash Investing And Financing Activities) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Cash Flow Information [Abstract]	'	'	'
Accrued capital expenditures	$420	$226	$108
Net gain from subsidiary common unit transactions	80	153	352
AmeriGas limited partner interest received in Propane Contribution (see Note 4)	1,123	0	0
Units issued in Southern Union Merger (See Note 3)	2,354	0	0
Long-term debt assumed and non-compete agreement notes payable issued from acquisitions	6,658	4	1,243
Subsidiary issuance of Common Units in connection with certain acquisitions	2,295	3	584
Cash paid for interest, net of interest capitalized	997	728	547
Cash paid for income taxes	$23	$27	$9

Estimates_Significant_Accounti6

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule of Inventory) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Inventory, Net [Abstract]	'	'
Natural gas and NGLs, excluding propane	$338	$146
Propane	0	87
Energy Related Inventory, Crude Oil, Products and Merchandise	418	0
Inventory, refined products	572	0
Appliances, parts and fittings and other	194	95
Total inventories	$1,522	$328

Estimates_Significant_Accounti7

Estimates, Significant Accounting Policies and Balance Sheet Detail (Other Current Assets) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Other Information [Abstract]	'	'
Deposits paid to vendors	$41	$66
Prepaid and other	270	118
Total other current assets	$311	$184

Estimates_Significant_Accounti8

Estimates, Significant Accounting Policies and Balance Sheet Detail (Property, Plant and Equipment) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	$30,388	$16,530
Less - Accumulated depreciation	-2,104	-1,971
PROPERTY, PLANT AND EQUIPMENT, net	28,284	14,559
Land and improvements [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	553	137
Buildings and improvements [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	587	279
Pipelines and equipment (5 to 83 years)	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	19,505	11,359
Natural gas and NGL storage facilities (5 to 46 years)	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	1,057	790
Bulk storage, equipment and facilities (5 to 83 years)	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	1,745	977
Tanks and other equipment (10 to 40 years)	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	1,194	644
Retail Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	258	0
Vehicles [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	96	231
Right of way (20 to 83 years)	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	2,134	793
Furniture and fixtures (3 to 12 years)	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	50	48
Linepack [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	118	59
Pad gas [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	58	58
Other (2 to 19 years)	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	1,060	234
Construction work-in-process [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	$1,973	$921

Estimates_Significant_Accounti9

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]	'	'	'
Depreciation expense (1)	$801	$531	$370
Capitalized interest, excluding AFUDC	99	13	4
PP&E [Member]	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down	128	'	'
Canyon [Member]	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Depreciation expense (1)	'	$26	$25

Recovered_Sheet1

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule Of Goodwill) (Details) (USD $)

12 Months Ended

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Oct. 05, 2012

Mar. 25, 2012

Dec. 31, 2012

Dec. 31, 2012

Mar. 25, 2012

Corporate And Others [Member]

Corporate And Others [Member]

ETP Intrastate Transportation and Storage [Member]

ETP Intrastate Transportation and Storage [Member]

ETP Interstate Transportation and Storage [Member]

ETP Interstate Transportation and Storage [Member]

ETP Midstream [Member]

ETP Midstream [Member]

ETP NGL Transportation and Services [Member]

ETP NGL Transportation and Services [Member]

ETP Retail Marketing [Member]

ETP Retail Marketing [Member]

Investment in Sunoco Logistics [Member]

Investment in Sunoco Logistics [Member]

Investment In Regency [Member]

Investment In Regency [Member]

Sunoco Merger [Member]

Southern Union Merger [Member]

Propane Business Deconsolidation [Member]

Distribution Operations [Member]

Distribution Operations [Member]

Goodwill [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill

$2,039,000,000

$1,601,000,000

$658,000,000

$652,000,000

$10,000,000

$10,000,000

$99,000,000

$99,000,000

$50,000,000

$50,000,000

$432,000,000

$0

$0

$0

$0

$0

$790,000,000

$790,000,000

'

'

'

'

'

Goodwill acquired

5,147,000,000

'

384,000,000

6,000,000

0

0

1,785,000,000

0

338,000,000

0

0

432,000,000

1,272,000,000

0

1,368,000,000

0

0

0

'

'

'

'

'

Goodwill

6,434,000,000

2,039,000,000

290,000,000

658,000,000

10,000,000

10,000,000

1,884,000,000

99,000,000

388,000,000

50,000,000

432,000,000

432,000,000

1,272,000,000

0

1,368,000,000

0

790,000,000

790,000,000

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Goodwill Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,640,000,000

2,500,000,000

'

'

133,000,000

Goodwill, impairment loss

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill, net increase

4,400,000,000

438,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill, Written off Related to Sale of Business Unit

($752,000,000)

'

($752,000,000)

'

$0

'

$0

'

$0

'

$0

'

$0

'

$0

'

$0

'

'

'

$619,000,000

$133,000,000

'

Recovered_Sheet2

Estimates, Significant Accounting Policies and Balance Sheet Detail (Components And Useful Lives Of Intangibles And Other Assets) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Accumulated Amortization, Intangibles, Gross	$160	$149
Gross Carrying Amount	2,150	1,142
Accumulated Amortization	-160	-149
Gross Carrying Amount, Total intangible assets	2,451	1,221
Trademarks [Member]	'	'
Accumulated Amortization	0	0
Gross Carrying Amount, Non-amortizable intangible assets	301	79
Customer relationships, contracts and agreements [Member]	'	'
Gross Carrying Amount	2,032	1,059
Accumulated Amortization	-150	-135
Trade names [Member]	'	'
Gross Carrying Amount	66	66
Accumulated Amortization	-8	-5
Intangible assets, useful life (years)	'20 years 0 months 0 days	'
Noncompete agreements [Member]	'	'
Gross Carrying Amount	0	15
Accumulated Amortization	0	-8
Patents [Member]	'	'
Gross Carrying Amount	48	1
Accumulated Amortization	-1	0
Intangible assets, useful life (years)	'9 years 0 months 0 days	'
Other [Member]	'	'
Gross Carrying Amount	4	1
Accumulated Amortization	($1)	($1)

Recovered_Sheet3

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule Of Finite-Lived Intangible Assets Acquired As Part Of Business Combination) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Oct. 05, 2012
Sunoco Merger [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets	'	$1,361
Customer Relationships, Contracts And Agreements [Member] | Holdco Transaction [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets	'	1,070,000
Trade Names [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets, useful life (years)	'20 years 0 months 0 days	'
Patents [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets, useful life (years)	'9 years 0 months 0 days	'
Patents [Member] | Holdco Transaction [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets	'	50,000
Intangible assets, useful life (years)	'10 years	'
Minimum [Member] | Customer Relationships, Contracts And Agreements [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets, useful life (years)	'3 years 0 months 0 days	'
Minimum [Member] | Customer Relationships, Contracts And Agreements [Member] | Holdco Transaction [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets, useful life (years)	'5 years	'
Maximum [Member] | Customer Relationships, Contracts And Agreements [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets, useful life (years)	'46 years 0 months 0 days	'
Maximum [Member] | Customer Relationships, Contracts And Agreements [Member] | Holdco Transaction [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets, useful life (years)	'20 years	'
Trademarks [Member] | Holdco Transaction [Member]	'	'
Business Acquisition [Line Items]	'	'
Intangible assets	'	$300,000

Recovered_Sheet4

Estimates, Significant Accounting Policies and Balance Sheet Detail (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) (Depreciation And Amortization [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Depreciation And Amortization [Member]	'	'	'
Reported in depreciation and amortization	$70	$55	$36

Recovered_Sheet5

Estimates, Significant Accounting Policies and Balance Sheet Detail (Estimated Aggregate Amortization Expense) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Goodwill and Intangible Assets Disclosure [Abstract]	'	'
2013	$116	'
2014	115	'
2015	115	'
2016	115	'
2017	115	'
Finite-Lived Intangible Assets, Gross	$2,150	$1,142

Recovered_Sheet6

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule of Other Non-Current Assets, net) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Unamortized financing costs (3 to 30 years)	$152	$132
Regulatory assets	93	89
Deferred Costs, Noncurrent	140	0
Other	148	28
Total other non-current assets, net	$533	$249

Recovered_Sheet7

Estimates, Significant Accounting Policies and Balance Sheet Detail (Accrued And Other Current Liabilities) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Other Information [Abstract]	'	'
Interest payable	$334	$204
Customer advances and deposits	61	101
Accrued capital expenditures	427	229
Accrued wages and benefits	250	80
Taxes payable other than income taxes	208	79
Income taxes payable	41	15
Deferred Tax Liabilities, Gross, Current	130	0
Other	303	56
Total accrued and other current liabilities	$1,754	$764

Recovered_Sheet8

Estimates, Significant Accounting Policies and Balance Sheet Detail (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Long-term Debt, Fair Value	$24,150,000,000	$12,210,000,000
Preferred Units	-331,000,000	-323,000,000
Long-term Debt	22,053,000,000	11,371,000,000
Fair Value, Measurements, Recurring [Member]	'	'
Marketable securities (included in other current assets)	'	1,000,000
Interest rate derivatives	55,000,000	36,000,000
Commodity derivatives:	156,000,000	305,000,000
Total Assets	211,000,000	342,000,000
Interest rate derivatives	-235,000,000	-117,000,000
Preferred Units	-331,000,000	-323,000,000
Embedded derivatives in the Regency Preferred Units	-25,000,000	-39,000,000
Commodity derivatives:	-168,000,000	-262,000,000
Total Liabilities	-759,000,000	-741,000,000
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]	'	'
Marketable securities (included in other current assets)	'	1,000,000
Interest rate derivatives	0	0
Commodity derivatives:	108,000,000	280,000,000
Total Assets	108,000,000	281,000,000
Interest rate derivatives	0	0
Preferred Units	0	0
Embedded derivatives in the Regency Preferred Units	0	0
Commodity derivatives:	-118,000,000	-233,000,000
Total Liabilities	-118,000,000	-233,000,000
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]	'	'
Marketable securities (included in other current assets)	'	0
Interest rate derivatives	55,000,000	36,000,000
Commodity derivatives:	48,000,000	25,000,000
Total Assets	103,000,000	61,000,000
Interest rate derivatives	-235,000,000	-117,000,000
Preferred Units	0	0
Embedded derivatives in the Regency Preferred Units	0	0
Commodity derivatives:	-50,000,000	-29,000,000
Total Liabilities	-285,000,000	-146,000,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]	'	'
Marketable securities (included in other current assets)	'	0
Interest rate derivatives	0	0
Commodity derivatives:	0	0
Total Assets	0	0
Interest rate derivatives	0	0
Preferred Units	-331,000,000	-323,000,000
Embedded derivatives in the Regency Preferred Units	-25,000,000	-39,000,000
Commodity derivatives:	0	0
Total Liabilities	-356,000,000	-362,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Condensate - Forward Swaps [Member]	'	'
Commodity derivatives:	2,000,000	1,000,000
Commodity derivatives:	'	-2,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Basis Swaps IFERC NYMEX [Member]	'	'
Commodity derivatives:	11,000,000	63,000,000
Commodity derivatives:	-18,000,000	-82,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Swing Swaps IFERC [Member]	'	'
Commodity derivatives:	3,000,000	15,000,000
Commodity derivatives:	-2,000,000	-16,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fixed Swaps/Futures [Member]	'	'
Commodity derivatives:	98,000,000	219,000,000
Commodity derivatives:	-103,000,000	-148,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Options - Puts [Member]	'	'
Commodity derivatives:	1,000,000	6,000,000
Commodity derivatives:	-1,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Options - Calls [Member]	'	'
Commodity derivatives:	-3,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Forward Physical Swaps [Member]	'	'
Commodity derivatives:	1,000,000	1,000,000
Commodity derivatives:	'	-1,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | NGLs - Forward Swaps [Member]	'	'
Commodity derivatives:	2,000,000	'
Commodity derivatives:	-4,000,000	-9,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Propane Forward Swaps [Member]	'	'
Commodity derivatives:	'	-4,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Options - Calls (MMBtu) [Member]	'	'
Commodity derivatives:	3,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Power - Forward Swaps [Member]	'	'
Commodity derivatives:	27,000,000	'
Commodity derivatives:	27,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Power - Futures [Member]	'	'
Commodity derivatives:	1,000,000	'
Commodity derivatives:	2,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Power - Option - Calls [Member]	'	'
Commodity derivatives:	2,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Refined Products [Member]	'	'
Commodity derivatives:	5,000,000	'
Commodity derivatives:	8,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Condensate - Forward Swaps [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	'	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Basis Swaps IFERC NYMEX [Member]	'	'
Commodity derivatives:	11,000,000	63,000,000
Commodity derivatives:	-18,000,000	-82,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Swing Swaps IFERC [Member]	'	'
Commodity derivatives:	0	2,000,000
Commodity derivatives:	0	-3,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]	'	'
Commodity derivatives:	94,000,000	215,000,000
Commodity derivatives:	-94,000,000	-148,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Options - Puts [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Options - Calls [Member]	'	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Forward Physical Swaps [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	'	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | NGLs - Forward Swaps [Member]	'	'
Commodity derivatives:	1,000,000	'
Commodity derivatives:	-3,000,000	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Propane Forward Swaps [Member]	'	'
Commodity derivatives:	'	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Options - Calls (MMBtu) [Member]	'	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Power - Forward Swaps [Member]	'	'
Commodity derivatives:	0	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Power - Futures [Member]	'	'
Commodity derivatives:	1,000,000	'
Commodity derivatives:	2,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Power - Option - Calls [Member]	'	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 1 [Member] | Refined Products [Member]	'	'
Commodity derivatives:	1,000,000	'
Commodity derivatives:	1,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Condensate - Forward Swaps [Member]	'	'
Commodity derivatives:	2,000,000	1,000,000
Commodity derivatives:	'	-2,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Basis Swaps IFERC NYMEX [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Swing Swaps IFERC [Member]	'	'
Commodity derivatives:	3,000,000	13,000,000
Commodity derivatives:	-2,000,000	-13,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]	'	'
Commodity derivatives:	4,000,000	4,000,000
Commodity derivatives:	-9,000,000	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Options - Puts [Member]	'	'
Commodity derivatives:	1,000,000	6,000,000
Commodity derivatives:	-1,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Options - Calls [Member]	'	'
Commodity derivatives:	-3,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Forward Physical Swaps [Member]	'	'
Commodity derivatives:	1,000,000	1,000,000
Commodity derivatives:	'	-1,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | NGLs - Forward Swaps [Member]	'	'
Commodity derivatives:	1,000,000	'
Commodity derivatives:	-1,000,000	-9,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Propane Forward Swaps [Member]	'	'
Commodity derivatives:	'	-4,000,000
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Options - Calls (MMBtu) [Member]	'	'
Commodity derivatives:	3,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Power - Forward Swaps [Member]	'	'
Commodity derivatives:	27,000,000	'
Commodity derivatives:	27,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Power - Futures [Member]	'	'
Commodity derivatives:	0	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Power - Option - Calls [Member]	'	'
Commodity derivatives:	2,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Level 2 [Member] | Refined Products [Member]	'	'
Commodity derivatives:	4,000,000	'
Commodity derivatives:	7,000,000	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Condensate - Forward Swaps [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	'	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Basis Swaps IFERC NYMEX [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Swing Swaps IFERC [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Swaps/Futures [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Options - Puts [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Options - Calls [Member]	'	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Forward Physical Swaps [Member]	'	'
Commodity derivatives:	0	0
Commodity derivatives:	'	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | NGLs - Forward Swaps [Member]	'	'
Commodity derivatives:	0	'
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Propane Forward Swaps [Member]	'	'
Commodity derivatives:	'	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Options - Calls (MMBtu) [Member]	'	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Power - Forward Swaps [Member]	'	'
Commodity derivatives:	0	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Power - Futures [Member]	'	'
Commodity derivatives:	0	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Power - Option - Calls [Member]	'	'
Commodity derivatives:	0	'
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | Refined Products [Member]	'	'
Commodity derivatives:	0	'
Commodity derivatives:	$0	'

Recovered_Sheet9

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates, Significant Accounting Policies and Balance Sheet Detail (Fair Value Schedule of Unobservable Inputs) (Details)	Dec. 31, 2012
Unobservable Inputs [Abstract]	'
Preferred Unit Yield Fair Value Assumption	6.11%
Fair Value Embedde Derivatives, Significant Unobservable Input, Credit Spread	6.49%
Fair Value, Embedded Derivatives, Significant Unobservable Input, Volatility	21.38%

Recovered_Sheet10

Estimates, Significant Accounting Policies and Balance Sheet Detail (Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2011
		Fair Value, Measurements, Recurring [Member]	Fair Value, Measurements, Recurring [Member]	Fair Value, Inputs, Level 3 [Member]	Fair Value, Inputs, Level 3 [Member]
				Fair Value, Measurements, Recurring [Member]	Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'	'	'
Net unrealized gains included in other income (expense)	$6	'	'	'	'
Liabilities, Fair Value Disclosure	'	($759)	($741)	($356)	($362)

Recovered_Sheet11

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates, Significatn Accounting Policies and Balance Sheet Detail (Schedule of Useful Lives) (Details) (Details)	12 Months Ended
	Dec. 31, 2012
Trade names [Member]	'
Intangible assets, useful life, minimum (years)	'20 years 0 months 0 days
Patents [Member]	'
Intangible assets, useful life, minimum (years)	'9 years 0 months 0 days
Minimum [Member] | Buildings and improvements [Member]	'
Property, plant and equipment, useful life, minimum (years)	'10 years 0 months 0 days
Minimum [Member] | Pipelines and equipment (5 to 83 years)	'
Property, plant and equipment, useful life, minimum (years)	'10 years 0 months 0 days
Minimum [Member] | Bulk storage, equipment and facilities (5 to 83 years)	'
Property, plant and equipment, useful life, minimum (years)	'5 years 0 months 0 days
Minimum [Member] | Tanks and other equipment (10 to 40 years)	'
Property, plant and equipment, useful life, minimum (years)	'10 years 0 months 0 days
Minimum [Member] | Vehicles [Member]	'
Property, plant and equipment, useful life, minimum (years)	'3 years 0 months 0 days
Minimum [Member] | Right of way (20 to 83 years)	'
Property, plant and equipment, useful life, minimum (years)	'20 years 0 months 0 days
Minimum [Member] | Furniture and Fixtures [Member]	'
Property, plant and equipment, useful life, minimum (years)	'3 years 0 months 0 days
Minimum [Member] | Property, Plant and Equipment, Other Types [Member]	'
Property, plant and equipment, useful life, minimum (years)	'5 years 0 months 0 days
Minimum [Member] | Customer relationships, contracts and agreements [Member]	'
Intangible assets, useful life, minimum (years)	'3 years 0 months 0 days
Minimum [Member] | Noncompete agreements [Member]	'
Intangible assets, useful life, minimum (years)	'3 years 0 months 0 days
Minimum [Member] | Other [Member]	'
Intangible assets, useful life, minimum (years)	'10 years 0 months 0 days
Maximum [Member] | Buildings and improvements [Member]	'
Property, plant and equipment, useful life, minimum (years)	'83 years 0 months 0 days
Maximum [Member] | Pipelines and equipment (5 to 83 years)	'
Property, plant and equipment, useful life, minimum (years)	'83 years 0 months 0 days
Maximum [Member] | Natural gas and NGL storage facilities (5 to 46 years)	'
Property, plant and equipment, useful life, minimum (years)	'40 years 0 months 0 days
Maximum [Member] | Bulk storage, equipment and facilities (5 to 83 years)	'
Property, plant and equipment, useful life, minimum (years)	'83 years 0 months 0 days
Maximum [Member] | Tanks and other equipment (10 to 40 years)	'
Property, plant and equipment, useful life, minimum (years)	'30 years 0 months 0 days
Maximum [Member] | Vehicles [Member]	'
Property, plant and equipment, useful life, minimum (years)	'33 years 0 months 0 days
Maximum [Member] | Right of way (20 to 83 years)	'
Property, plant and equipment, useful life, minimum (years)	'83 years 0 months 0 days
Maximum [Member] | Furniture and Fixtures [Member]	'
Property, plant and equipment, useful life, minimum (years)	'33 years 0 months 0 days
Maximum [Member] | Property, Plant and Equipment, Other Types [Member]	'
Property, plant and equipment, useful life, minimum (years)	'33 years 0 months 0 days
Maximum [Member] | Customer relationships, contracts and agreements [Member]	'
Intangible assets, useful life, minimum (years)	'46 years 0 months 0 days
Maximum [Member] | Noncompete agreements [Member]	'
Intangible assets, useful life, minimum (years)	'15 years 0 months 0 days
Maximum [Member] | Other [Member]	'
Intangible assets, useful life, minimum (years)	'15 years 0 months 0 days

Recovered_Sheet12

Estimates, Significant Accounting Policies and Balance Sheet Detail (Asset Retirement Obligations) (Details) (USD $)	Dec. 31, 2012
In Millions, unless otherwise specified
Asset Retirement Obligation	$140
Southern Union [Member]	'
Asset Retirement Obligation	46
Sunoco [Member]	'
Asset Retirement Obligation	53
Sunoco Logistics [Member]	'
Asset Retirement Obligation	$41

Acquisitions_and_Related_Trans2

Acquisitions and Related Transactions (Narrative) (Details) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

Mar. 31, 2012

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Oct. 05, 2012

25-May-10

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Oct. 05, 2012

Dec. 31, 2012

25-May-10

27-May-10

Dec. 31, 2012

Oct. 05, 2012

Jan. 12, 2012

Jan. 12, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Sep. 30, 2011

Dec. 31, 2012

Sep. 30, 2011

27-May-10

25-May-10

Dec. 31, 2012

Mar. 25, 2012

Mar. 25, 2012

Dec. 31, 2010

25-May-10

Sep. 30, 2010

Mar. 31, 2010

Mar. 31, 2012

Dec. 31, 2012

Mar. 25, 2012

Dec. 31, 2012

Oct. 05, 2012

Mar. 25, 2012

Dec. 31, 2012

Oct. 31, 2012

Oct. 05, 2012

Oct. 05, 2012

Jul. 31, 2011

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Regency [Member]

Regency [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP's Propane Operations [Member]

Carlyle Group [Member]

Sunoco [Member]

Lone Star L.L.C. [Member]

Lone Star L.L.C. [Member]

Lone Star L.L.C. [Member]

Lone Star L.L.C. [Member]

MEP [Member]

MEP [Member]

Southern Union Merger [Member]

Southern Union Merger [Member]

SUG Merger [Member]

SUG Merger [Member]

Regency [Member]

Zephyr [Member]

Other Acquisiitons [Member]

Citrus Merger [Member]

Citrus Merger [Member]

Citrus Merger [Member]

Sunoco Merger [Member]

Sunoco Merger [Member]

Sunoco Merger [Member]

Sunoco Merger [Member]

Holdco Transaction [Member]

Holdco Transaction [Member]

Holdco Transaction [Member]

East Texas Gathering And Processing Assets [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

SUGS Contribution [Member]

SUGS Contribution [Member]

SUGS Contribution [Member]

Class F Units [Member]

PES Joint Venture [Member]

PES Joint Venture [Member]

Regency [Member]

Regency [Member]

ETP [Member]

ETP [Member]

Regency [Member]

Regency [Member]

ETE Preferred Units [Member]

Regency [Member]

ETP [Member]

quarters

Sunoco Logistics [Member]

quarters

Sunoco [Member]

Regency [Member]

Revolving Credit Facility [Member]

ETP [Member]

Southern Union [Member]

SUGS Contribution [Member]

mile

Length of pipeline acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

120

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Subsidiary Interest in Joint Venture

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

67.00%

30.00%

30.00%

30.00%

70.00%

70.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Retained Interest, Fair Value Disclosure

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest ownership

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

49.90%

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash paid in Acquisition

'

1,980,000,000

'

'

'

'

'

'

'

1,980,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,010,000,000

'

'

'

'

'

'

'

'

'

'

2,600,000,000

'

'

'

'

'

'

'

30,000,000

570,000,000

'

Consideration of Acquisition

'

'

'

'

'

'

'

'

'

'

'

'

'

305,000,000

'

'

'

'

'

'

'

'

'

'

1,460,000,000

'

'

592,700,000

'

1,380,000,000

'

'

'

'

'

3,010,000,000

'

'

193,300,000

150,000,000

'

1,900,000,000

1,900,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition Units Acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

26,300,000

'

'

'

30,000,000

'

'

'

'

'

'

'

'

'

'

56,982,160

'

0

'

'

'

'

'

'

'

'

55,000,000

'

'

'

'

'

'

'

'

'

'

Part Noncash Divestiture, Amount of Noncash Consideration Received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

71,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revolving credit facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000,000

'

'

'

'

Equity method investment, acquire additional ownership percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.10%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock Redeemed or Called During Period, Shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisition of all outstanding shares of SUG, total transaction price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,365,000

'

'

'

'

'

'

2,000,000,000

2,000,000,000

'

5,775,000

'

'

'

'

'

'

'

'

'

'

'

Temporary Equity, Shares Issued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred units liquidation preference

'

300,000,000

'

'

'

'

'

'

'

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Customer contracts recorded in connection with business acquisition, amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

68,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Goodwill Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,497,000

'

'

'

0

27,000,000

'

'

'

'

2,641,000

'

'

'

'

'

'

'

'

'

'

'

Business acquisition intangible assets recorded, value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

55,000

'

'

'

119,000,000

'

'

'

'

'

1,361,000

'

'

'

'

'

'

'

'

'

'

'

Cash received from sale of assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

70,000,000

'

'

'

'

'

Liabilities assumed in connection with business acquisition, amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,171,000

'

'

'

'

'

'

'

'

'

13,414,000

'

'

'

'

'

'

'

'

'

'

'

Contingent Residual Support Agreement Obligation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Of Subsidiary Guaranteed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares

2,250,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,372,419

'

'

6,274,483

Relinquishment Of Rights Of Incentive Distributions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

220,000,000

'

'

'

'

'

'

210,000,000

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

16

'

'

'

'

'

12

'

'

'

'

'

'

'

Business Combination, Acquisition Related Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

38,000,000

'

'

'

'

'

'

'

'

'

28,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

11,313,000,000

2,107,000,000

1,875,000,000

1,669,000,000

2,166,000,000

2,084,000,000

1,963,000,000

1,977,000,000

16,964,000,000

8,190,000,000

6,556,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,260,000,000

'

'

'

'

'

'

'

'

'

5,930,000,000

'

'

3,110,000,000

'

'

'

'

'

'

'

'

'

General Partner Interest

'

'

'

'

'

'

'

'

'

'

'

'

2.00%

'

'

'

'

'

1.60%

'

'

0.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Incentive Distribution Rights

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

100.00%

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent of total equity ownership of a subsidiary

'

'

'

'

'

'

'

'

'

'

'

'

32.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity interest in Holdco

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60.00%

'

'

'

40.00%

40.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-37,000

'

'

'

'

'

'

'

'

'

-2,714,000

'

'

'

'

2,000,000,000

'

'

'

'

'

'

Class F Units Issued in Holdco Transaction

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

90,706,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Class F Unit Distribution Rate

'

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Class F Unit Maximum Distribution

'

'

'

'

'

'

'

'

'

'

'

'

$3.75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income (Loss) Attributable to Parent

'

'

'

'

'

'

'

'

'

$304,000,000

$310,000,000

$193,000,000

'

'

$304,000,000

$310,000,000

$193,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$39,000,000

'

'

'

'

'

'

'

'

'

$14,000,000

'

'

$145,000,000

'

'

'

'

'

'

'

'

'

Acquisitions_and_Related_Trans3

Acquisitions and Related Transactions (Pro Forma Results Of Operations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Business Acquisition [Line Items]	'	'	'
Revenues	$40,398,000,000	$37,560,000,000	$7,407
Net income	868,000,000	865,000,000	358
Net income attributable to partners	$866,000,000	$863,000,000	$228
Basic net income (loss) per Limited Partner unit	$3.09	$3.08	$1.02
Diluted net income (loss) per Limited Partner unit	$3.09	$3.08	$1.02

Acquisitions_and_Related_Trans4

Acquisitions and Related Transactions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Oct. 05, 2012	Mar. 25, 2012
			Sunoco Merger [Member]	Southern Union Merger [Member]
Business Acquisition [Line Items]	'	'	'	'
Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt	'	'	$2,879,000	$3,120,000
Convertible Preferred Units	331,000,000	323,000,000	'	'
Total current assets	'	'	7,312,000	556,000
Property, plant, and equipment	'	'	6,686,000	6,242,000
Goodwill	'	'	2,641,000	2,497,000
Intangible assets	'	'	1,361,000	55,000
Other assets	'	'	128,000	163,000
Business Acquisition, Purchase Price Allocation, Current Liabilities	'	'	4,424,000	1,348,000
Business Acquisition, Purchase Price Allocation, Deferred Taxes Asset (Liability), Net, Noncurrent	'	'	1,762,000	1,419,000
Total assets	'	'	19,189,000	11,536,000
Other long-term liabilities	'	'	769,000	284,000
Total liabilities	'	'	13,414,000	6,171,000
Total consideration	'	'	5,775,000	5,365,000
Cash received	'	'	2,714,000	37,000
Total consideration, net of cash received	'	'	3,061,000	5,328,000
Business Acquisition, Purchase Price Allocation, Investments in Affilaites	'	'	240,000	2,023,000
Business Acquisition, Purchase Price Allocation, Note Receivable	'	'	821,000	0
Business Acquisition, Purchase Price Allocation, Noncontrolling Interest	'	'	$3,580,000	$0

Acquisitions_and_Related_Trans5

Acquisitions and Related Transactions Discontinued Operations (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2012	Mar. 25, 2012	Jan. 12, 2012
		Canyon [Member]	Distribution Operations [Member]	Distribution Operations [Member]	Distribution Operations [Member]	ETP [Member]
Disposal Group, Including Discontinued Operation, Revenue	'	'	$324,000,000	'	'	'
Contingent Residual Support Agreement Obligation	'	'	'	'	'	1,500,000,000
Proceeds from Sale of Property, Plant, and Equipment	'	207,000,000	'	'	'	'
Write-down of assets included in loss from discontinued operations (See Note 3)	'	132,000,000	'	'	'	'
Business Combination, Consideration Transferred	1,980,000,000	'	1,040,000,000	1,040,000,000	'	'
Debt Of Subsidiary Guaranteed	'	'	'	'	'	1,500,000,000
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax	'	'	43,000,000	'	'	'
Part Noncash Divestiture, Amount of Noncash Consideration Received	'	'	'	19,000,000	'	'
Business Acquisition, Purchase Price Allocation, Goodwill Amount	'	'	'	'	$133,000,000	'

Acquisitions_and_Related_Trans6

Acquisitions and Related Transactions 2011 Transactions (Details) (USD $)	Dec. 31, 2012	25-May-10	Dec. 31, 2012	Sep. 30, 2011	Dec. 31, 2012	Sep. 30, 2011
In Millions, unless otherwise specified			ETP [Member]	ETP [Member]	Regency [Member]	Regency [Member]
			Lone Star L.L.C. [Member]	Lone Star L.L.C. [Member]	Lone Star L.L.C. [Member]	Lone Star L.L.C. [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'
Subsidiary Interest in Joint Venture	'	'	70.00%	70.00%	30.00%	30.00%
Business Combination, Consideration Transferred	$1,980	'	'	'	'	'
Business Acquisition, Cost of Acquired Entity, Cash Paid	'	$305	$1,380	'	$592.70	'

Acquisitions_and_Related_Trans7

Acquisitions and Related Transactions 2010 Transactions (Details) (USD $)	Dec. 31, 2012	25-May-10	25-May-10	27-May-10	Jan. 12, 2012	Mar. 31, 2010	25-May-10	Sep. 30, 2010	27-May-10	25-May-10	Jul. 31, 2011
			ETE Preferred Units [Member]	ETP [Member]	ETP [Member]	ETP [Member]	Regency [Member]	Regency [Member]	Regency [Member]	Regency [Member]	East Texas Gathering And Processing Assets [Member]
			Regency [Member]			Other Acquisiitons [Member]		Zephyr [Member]	MEP [Member]	MEP [Member]	Regency [Member]
						mile
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Length Of Pipeline	'	'	'	'	'	120	'	'	'	'	'
Temporary Equity, Shares Issued	'	'	3,000,000	'	'	'	'	'	'	'	'
Preferred units liquidation preference	$300,000,000	'	$300,000,000	'	'	'	'	'	'	'	'
Interest ownership	'	'	'	'	'	'	'	'	'	49.90%	'
Equity method investment, acquire additional ownership percentage	'	'	'	'	'	'	'	'	0.10%	'	'
Business Acquisition, Cost of Acquired Entity, Cash Paid	'	305,000,000	'	'	'	150,000,000	'	193,300,000	'	'	'
Business acquisition intangible assets recorded, value	'	'	'	'	'	'	'	119,000,000	'	'	'
Stock Redeemed or Called During Period, Shares	'	'	'	12,300,000	'	'	'	'	'	'	'
Business Acquisition Units Acquired	'	'	'	'	30,000,000	'	26,300,000	'	'	'	'
Customer contracts recorded in connection with business acquisition, amount	'	'	'	'	'	68,000,000	'	'	'	'	'
Business Acquisition, Purchase Price Allocation, Goodwill Amount	'	'	'	'	'	27,000,000	'	0	'	'	'
Proceeds from Divestiture of Businesses, Net of Cash Divested	'	'	'	'	'	'	'	'	'	'	$70,000,000

Advances_to_and_Investments_in2

Advances to and Investments in Unconsolidated Affiliates (Details) (USD $)

12 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

25-May-10

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Jan. 12, 2012

Jan. 12, 2012

Jan. 12, 2012

25-May-10

25-May-10

Dec. 31, 2012

Mar. 25, 2012

Dec. 31, 2012

Jun. 30, 2012

Dec. 31, 2012

Citrus [Member]

FGT [Member]

Fayetteville Express Pipeline, LLC [Member]

Midcontinent Express Pipeline, LLC [Member]

RIGS Haynesville Partnership Co. [Member]

AmeriGas [Member]

ETP [Member]

ETP [Member]

Regency [Member]

MEP [Member]

Citrus Merger [Member]

Citrus Merger [Member]

Citrus [Member]

Propane Cylinder Exchange Business [Member]

AmeriGas [Member]

years

AmeriGas [Member]

Regency [Member]

ETP [Member]

ETP [Member]

ETP [Member]

Interest ownership

'

'

'

'

50.00%

'

50.00%

50.00%

50.00%

'

'

'

'

49.90%

'

50.00%

'

'

'

Percentage ownership operating facility

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Cost of Acquired Entity, Cash Paid

'

'

'

$305,000,000

'

'

'

'

'

'

'

'

'

'

$1,900,000,000

$1,900,000,000

'

'

'

Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

'

'

Business Acquisition, Cost of Acquired Entity, Purchase Price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,000,000,000

2,000,000,000

'

'

'

Equity Method Investment, Difference Between Carrying Amount and Underlying Equity

'

'

'

'

'

'

'

'

'

630,000,000

'

'

'

'

1,030,000,000

'

'

'

'

Proceeds from Divestiture of Businesses

207,000,000

0

0

'

'

'

'

'

'

'

1,460,000,000

'

'

'

'

'

'

43,000,000

'

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES

4,737,000,000

1,497,000,000

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

1,980,000,000

'

1,020,000,000

Business Acquisition Units Acquired

'

'

'

'

'

'

'

'

'

'

30,000,000

'

26,300,000

'

'

'

'

'

'

AmeriGas limited partner interest received in Propane Contribution (see Note 4)

1,123,000,000

0

0

'

'

'

'

'

'

'

1,120,000,000

71,000,000

'

'

'

'

'

'

'

Gain on deconsolidation of Propane Business

1,057,000,000

0

0

'

'

'

'

'

'

'

1,060,000,000

'

'

'

'

'

'

'

'

Equity in earnings of unconsolidated affiliates

212,000,000

117,000,000

65,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Method Investment, Difference Between Carrying Amount and Underlying Equity, Amortizable Amount

'

'

'

'

'

'

'

'

'

'

'

289,000,000

'

'

'

'

'

'

'

Equity Method Investment, Difference Between Carrying Amount and Underlying Equity, Weighted Average Amortization (years)

'

'

'

'

'

'

'

'

'

14

'

'

'

'

'

'

'

'

'

Equity Method Investment, Difference Between Carrying Amount and Underlying Equity, Equity Method Goodwill

'

'

'

'

'

'

'

'

'

'

'

$341,000,000

'

'

'

'

'

'

'

Advances_to_and_Investments_in3

Advances to and Investments in Unconsolidated Affiliates (Schedule Of Aggregated Balance Sheet Information Of Unconsolidated Affiliates) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Investment In Affiliates [Abstract]	'	'
Equity Method Investment, Summarized Financial Information, Current Assets	$945	$893
Property, plant and equipment, net	10,979	10,393
Other assets	2,677	962
Total assets	14,601	12,248
Current Liabilities	1,662	1,548
Non-current liabilities	7,024	5,778
Equity	5,915	4,922
Total liabilities and equity	$14,601	$12,248

Advances_to_and_Investments_in4

Advances to and Investments in Unconsolidated Affiliates (Pro Forma Results Of Operations) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Investment In Affiliates [Abstract]	'	'	'
Revenues	$4,492	$3,784	$3,287
Operating Income	863	928	716
Net income	$491	$536	$506

Net_Income_Per_Limited_Partner2

Net Income Per Limited Partner Unit (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share [Abstract]	'	'	'
Income (loss) from continuing operations	$1,383	$531	$345
Income (Loss) from Continuing Operations Attributable to Noncontrolling Interest	1,070	221	149
Income from continuing operations, net of noncontrolling interest	313	310	196
General Partner’s interest in income from continuing operations	1	1	1
Income from continuing operations available to Limited Partners	312	309	195
Weighted average Limited Partner units	266,722,030	222,968,261	222,941,156
Basic	1.17	1.39	0.87
Income (Loss) from Discontinued Operations, Net of Tax, Per Basic Share	($0.04)	$0	($0.01)
Dilutive effect of equity-based compensation of subsidiaries	-1	-1	0
Diluted net income (loss) available to Limited Partners	311	308	195
Weighted average Limited Partner units	266,722,030	222,968,261	222,941,156
Diluted	1.17	1.38	0.87
Preferred units liquidation preference	$300	'	'
Income (Loss) from Discontinued Operations, Net of Tax, Per Diluted Share	($0.04)	$0	($0.01)

Debt_Obligations_Debt_Obligati1

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Debt Instrument [Line Items]	'	'
Other Long-term Debt	'	$0
Unamortized Net Premiums And Fair Value Adjustments	386	'
Long-term Debt	22,053	11,371
Current maturities of long-term debt	-613	-424
LONG-TERM DEBT, less current maturities	21,440	10,947
Parent Company [Member]	'	'
Debt Instrument [Line Items]	'	'
Other Long-term Debt	19	1
Unamortized Net Premiums And Fair Value Adjustments	-34	-1
Current maturities of long-term debt	-4	0
LONG-TERM DEBT, less current maturities	3,840	1,872
Parent Company [Member] | ETE Senior Notes, due October 15, 2020 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	1,800	1,800
Parent Company [Member] | ETE Senior Secured Term Loan [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	2,000	0
Parent Company [Member] | ETE Senior Secured Revolving Credit Facilities [Member]	'	'
Debt Instrument [Line Items]	'	'
Outstanding borrowings	60	72
ETP [Member]	'	'
Debt Instrument [Line Items]	'	'
Other Long-term Debt	0	81
Unamortized Net Premiums And Fair Value Adjustments	-14	-2
ETP [Member] | Revolving Credit Facility [Member]	'	'
Debt Instrument [Line Items]	'	'
Outstanding borrowings	1,395	314
ETP [Member] | 5.65% Senior Notes due August 1, 2012 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	0	400
ETP [Member] | 6.0% Senior Notes due July 1, 2013 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	350	350
ETP [Member] | 8.5% Senior Notes due April 15, 2014 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	292	350
ETP [Member] | 5.95% Senior Notes due February 1, 2015 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	750	750
ETP [Member] | 6.125% Senior Notes due February 15, 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	400	400
ETP [Member] | 6.7% Senior Notes due July 1, 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	600	600
ETP [Member] | 9.7% Senior Notes due March 15, 2019 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	400	600
ETP [Member] | 9.0% Senior Notes due April 15, 2019 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	450	650
ETP [Member] | 4.65% Senior Notes due June 1, 2021 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	800	800
ETP [Member] | 6.625% Senior Notes due October 15, 2036 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	400	400
ETP [Member] | 7.5% Senior Notes due July 1, 2038 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	550	550
ETP [Member] | 6.05% Senior Notes due June 1, 2041 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	700	700
ETP [Member] | 6.875% Senior Notes due December 1, 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	1,000	0
ETP [Member] | 6.5% Senior Notes due July 15, 2021[Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	1,000	0
Regency [Member]	'	'
Debt Instrument [Line Items]	'	'
Unamortized Net Premiums And Fair Value Adjustments	3	5
Regency [Member] | Revolving Credit Facility [Member]	'	'
Debt Instrument [Line Items]	'	'
Outstanding borrowings	192	332
Regency [Member] | 6.125% Senior Notes due February 15, 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	700	0
Regency [Member] | 9.375% Senior Notes due June 1,2016 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	162	250
Regency [Member] | 6.875% Senior Notes due December 1, 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	600	600
Regency [Member] | 6.5% Senior Notes due July 15, 2021[Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	500	500
SUG [Member]	'	'
Debt Instrument [Line Items]	'	'
Unamortized Net Premiums And Fair Value Adjustments	49	0
SUG [Member] | ETE Senior Notes, due October 15, 2020 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	360	0
SUG [Member] | Revolving Credit Facility [Member]	'	'
Debt Instrument [Line Items]	'	'
Outstanding borrowings	210	0
SUG [Member] | 5.65% Senior Notes due August 1, 2012 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	300	0
SUG [Member] | Junior Subordinated Debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	600	0
Southern Union [Member]	'	'
Debt Instrument [Line Items]	'	'
Other Long-term Debt	7	'
Sunoco [Member]	'	'
Debt Instrument [Line Items]	'	'
Other Long-term Debt	25	0
Sunoco [Member] | ETE Senior Notes, due October 15, 2020 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	250	0
Sunoco [Member] | 5.65% Senior Notes due August 1, 2012 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	250	0
Sunoco [Member] | 6.0% Senior Notes due July 1, 2013 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	400	0
Sunoco [Member] | 6.125% Senior Notes due February 15, 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	65	0
Unamortized Net Premiums And Fair Value Adjustments	104	0
Sunoco Logistics [Member] | Sunoco Logistics Revolving Credit Facility, due August 2013 [Member]	'	'
Debt Instrument [Line Items]	'	'
Outstanding borrowings	26	0
Sunoco Logistics [Member] | ETE Senior Notes, due October 15, 2020 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	175	0
Sunoco Logistics [Member] | 5.65% Senior Notes due August 1, 2012 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	175	0
Sunoco Logistics [Member] | 6.0% Senior Notes due July 1, 2013 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	250	0
Sunoco Logistics [Member] | 8.5% Senior Notes due April 15, 2014 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	250	0
Sunoco Logistics [Member] | 5.95% Senior Notes due February 1, 2015 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	300	0
Sunoco Logistics [Member] | 6.7% Senior Notes due July 1, 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	300	0
Sunoco Logistics [Member] | Sunoco Logistics Revolving Credit Facility, due April 2015 [Member]	'	'
Debt Instrument [Line Items]	'	'
Outstanding borrowings	20	0
Sunoco Logistics [Member] | Sunoco Logistics Revolving Credit Facility, due August 2016 [Member]	'	'
Debt Instrument [Line Items]	'	'
Outstanding borrowings	93	0
Unamortized Net Premiums And Fair Value Adjustments	143	0
Transwestern [Member] | Unsecured Debt [Member] | 5.39% Senior Notes due November 17, 2014 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	88	88
Transwestern [Member] | Unsecured Debt [Member] | 5.54% Senior Notes due November 17, 2016 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	125	125
Transwestern [Member] | Unsecured Debt [Member] | 5.64% Senior Notes due May 24, 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	82	82
Transwestern [Member] | Unsecured Debt [Member] | 5.36% Senior Notes due December 9, 2020 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	175	175
Transwestern [Member] | Unsecured Debt [Member] | 5.89% Senior Notes due May 24, 2022 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	150	150
Transwestern [Member] | Unsecured Debt [Member] | 5.66% Senior Notes due December 9, 2024 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	175	175
Transwestern [Member] | Unsecured Debt [Member] | 6.16% Senior Notes due May 24, 2037 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	75	75
Unamortized Net Premiums And Fair Value Adjustments	-1	-1
Panhandle [Member]	'	'
Debt Instrument [Line Items]	'	'
Unamortized Net Premiums And Fair Value Adjustments	136	0
Panhandle [Member] | ETE Senior Notes, due October 15, 2020 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	250	0
Panhandle [Member] | 5.65% Senior Notes due August 1, 2012 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	300	0
Panhandle [Member] | 6.0% Senior Notes due July 1, 2013 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	400	0
Panhandle [Member] | 8.5% Senior Notes due April 15, 2014 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	150	0
Panhandle [Member] | 5.95% Senior Notes due February 1, 2015 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	66	0
Panhandle [Member] | Term Loan [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	$455	$0

Debt_Obligations_Debt_Obligati2

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Long-term Debt, by Maturity [Abstract]	'	'
Total	$22,053	$11,371
Unamortized Discounts And Fair Value Adjustments	386	'
Consolidated Total (excluding propane business) [Member]	'	'
Long-term Debt, by Maturity [Abstract]	'	'
2012	613	'
2013	1,003	'
2014	1,540	'
2015	2,073	'
2016	3,184	'
Thereafter	13,254	'
Total	$21,667	'

Debt_Obligations_Senior_Notes_

Debt Obligations (Senior Notes) (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Write off of Deferred Debt Issuance Cost	'	'	$0
Losses on extinguishments of debt	-123	0	-16
ETE Senior Secured Term Loan [Member]	'	'	'
Debt Instrument, Interest Rate, Effective Percentage	3.75%	'	'
Bridge Loan [Member]	'	'	'
Write off of Deferred Debt Issuance Cost	62	'	'
Panhandle [Member] | Term Loan [Member]	'	'	'
Debt Instrument, Interest Rate, Effective Percentage	1.84%	'	'
Senior Notes	455	0	'
Panhandle [Member] | 5.65% Senior Notes due August 1, 2012 [Member]	'	'	'
Senior Notes	300	0	'
Panhandle [Member] | 8.5% Senior Notes due April 15, 2014 [Member]	'	'	'
Senior Notes	150	0	'
SUG [Member] | Junior Subordinated Debt [Member]	'	'	'
Debt Instrument, Interest Rate, Effective Percentage	3.32%	'	'
Long-term Debt, Percentage Bearing Variable Interest, Amount	525	'	'
Senior Notes	600	0	'
Debt Instrument, Description of Variable Rate Basis	'three-month LIBOR rate plus 3.0175%	'	'
SUG [Member] | 5.65% Senior Notes due August 1, 2012 [Member]	'	'	'
Senior Notes	300	0	'
SUG [Member] | Variable Rate Portion of Debt [Member] | Junior Subordinated Debt [Member]	'	'	'
Senior Notes	$75	'	'
Federal Funds Effective Rate [Member] | ETE Senior Secured Term Loan [Member]	'	'	'
Debt Instrument, Basis Spread on Variable Rate	0.50%	'	'
Base Rate Loans [Member] | ETE Senior Secured Term Loan [Member]	'	'	'
Debt Instrument, Basis Spread on Variable Rate	2.00%	'	'
LIBOR [Member] | ETE Senior Secured Term Loan [Member]	'	'	'
Debt Instrument, Basis Spread on Variable Rate	1.00%	'	'
Eurodollar Loans [Member] | ETE Senior Secured Term Loan [Member]	'	'	'
Debt Instrument, Basis Spread on Variable Rate	3.00%	'	'

Debt_Obligations_Parent_Compan

Debt Obligations (Parent Company Credit Agreement) (Narrative) (Details) (USD $)

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

In Millions, unless otherwise specified

ETE Senior Secured Revolving Credit Facilities [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

Revolving Credit Facility [Member]

Eurodollar Loans [Member]

Base Rate Loans [Member]

Federal Funds Effective Rate [Member]

Federal Funds Effective Rate [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Parent Company [Member]

Parent Company [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

ETE Senior Secured Term Loan [Member]

ETE Senior Secured Term Loan [Member]

ETE Senior Secured Term Loan [Member]

Revolving Credit Facility [Member]

Eurodollar Loans [Member]

Base Rate Loans [Member]

Federal Funds Effective Rate [Member]

Eurodollar Loans [Member]

Base Rate Loans [Member]

Federal Funds Effective Rate [Member]

years

ETE Senior Secured Revolving Credit Facilities [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

Line of credit facility, unused capacity, commitment fee percentage

'

'

'

'

'

'

'

'

'

0.50%

'

'

0.75%

Revolving credit facility

'

'

$200

'

'

'

'

'

'

'

'

'

'

Term of revolving credit faciltiy

'

'

5

'

'

'

'

'

'

'

'

'

'

Debt instrument, basis spread on variable rate

'

'

'

3.00%

2.00%

0.50%

0.50%

2.75%

1.75%

'

3.75%

2.75%

'

Outstanding borrowings

60

72

'

'

'

'

'

'

'

'

'

'

'

Amount available for future borrowings

$140

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average interest rate on amount outstanding

4.06%

'

'

'

'

'

'

'

'

'

'

'

'

Debt_Obligations_ETP_Credit_Fa

Debt Obligations (ETP Credit Facility) (Narrative) (Details) (USD $)

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

ETE Senior Secured Revolving Credit Facilities [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

ETP Credit Facility [Member]

Southern Union Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Federal Funds Effective Rate [Member]

LIBOR [Member]

LIBOR [Member]

Parent Company [Member]

Parent Company [Member]

ETP [Member]

ETP [Member]

SUG [Member]

SUG [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

Revolving Credit Facility [Member]

ETP Credit Facility [Member]

Revolving Credit Facility [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

ETE Senior Secured Revolving Credit Facilities [Member]

Revolving credit facility

'

'

$2,500,000,000

$700,000,000

'

'

'

'

$200,000,000

'

'

'

Line of credit facility updated borrowing capacity subject to lender approval

'

'

3,750,000,000

'

'

'

'

'

'

'

'

'

Amount Outstanding

60,000,000

72,000,000

'

'

1,395,000,000

314,000,000

210,000,000

0

'

'

'

'

Amount available for future borrowings

140,000,000

'

1,030,000,000

'

'

'

'

'

'

'

'

'

Letters of credit outstanding, amount

'

'

'

'

$72,000,000

'

'

'

'

'

'

'

Weighted average interest rate on amount outstanding

4.06%

'

'

1.84%

1.71%

'

'

'

'

'

'

'

Debt instrument, basis spread on variable rate

'

'

'

'

'

'

'

'

'

0.50%

1.50%

1.00%

Line of credit facility, unused capacity, commitment fee percentage

'

'

0.25%

'

'

'

'

'

'

'

'

'

Debt_Obligations_Regency_Credi

Debt Obligations (Regency Credit Facility) (Narrative) (Details) (Regency Credit Facility [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Revolving credit facility	$1,150
Letters of credit availablity	200
Debt instrument, maturity date	15-Jun-14
Line of credit facility fronting fee percentage	0.13%
Outstanding borrowings	192
Letters of credit outstanding, amount	12
Amount available for future borrowings	$946
Weighted average interest rate on amount outstanding	2.93%
Federal Funds Effective Rate [Member]	'
Debt instrument, basis spread on variable rate	0.50%
LIBOR [Member]	'
Debt instrument, basis spread on variable rate	1.00%
Minimum [Member]	'
Line of credit facility, unused capacity, commitment fee percentage	0.38%
Line of credit participation fee	2.50%
Minimum [Member] | Base Rate Loans [Member]	'
Debt instrument, basis spread on variable rate	1.50%
Minimum [Member] | Eurodollar Loans [Member]	'
Debt instrument, basis spread on variable rate	2.50%
Maximum [Member]	'
Line of credit facility, unused capacity, commitment fee percentage	0.50%
Line of credit participation fee	3.25%
Maximum [Member] | Base Rate Loans [Member]	'
Debt instrument, basis spread on variable rate	2.25%
Maximum [Member] | Eurodollar Loans [Member]	'
Debt instrument, basis spread on variable rate	3.25%

Debt_Obligations_Debt_Obligati3

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2012
Debt Instrument [Line Items]	'
Debt instrument covenant maximum leverage ratio	4.5
Debt instrument covenant maximum leverage ratio, permitted during specific acquisition period	5
Debt instrument coveneant maximum consolidated leverage ratio	5.5
Debt instrument covenant minimum fixed charge coverage ratio	3
Debt instrument covenant minimum value to loan ratio	2
ETP [Member]	'
Debt Instrument [Line Items]	'
Debt instrument covenant maximum leverage ratio	5
Debt instrument covenant maximum leverage ratio, permitted during specific acquisition period	5.5
Regency [Member]	'
Debt Instrument [Line Items]	'
Maximum consolidated EBITDA ratio	5.25
Maximum consolidated EBITA to consolidated interest expense	2.75
Maximum consolidated senior secured leverage ratio	3
Southern Union [Member] | Southern Union Credit Facility [Member]	'
Debt Instrument [Line Items]	'
Maximum consolidated EBITA to consolidated interest expense	2
Debt to capitalization ratio maximum permitted	525.00%
Southern Union [Member] | Minimum Amount for Cross Default Swaps [Member]	'
Debt Instrument [Line Items]	'
Debt Covenant, Cross Default Feature, Minimum Amount	0

Debt_Obligations_Debt_Obligati4

Debt Obligations Debt Obligations (Sunoco Credit Facility) (Narrative) (Details) (USD $)	Dec. 31, 2012
In Millions, unless otherwise specified
Sunoco Logistics Revolving Credit Facility, due August 2016 [Member]	'
Revolving credit facility	$350
Sunoco Logistics Revolving Credit Facility, due August 2013 [Member]	'
Revolving credit facility	200
Sunoco Logistics [Member] | Sunoco Logistics Revolving Credit Facility, due April 2015 [Member]	'
Outstanding borrowings	20
Sunoco Logistics [Member] | Sunoco Logistics Revolving Credit Facility, due August 2016 [Member]	'
Outstanding borrowings	93
Sunoco Logistics [Member] | Sunoco Logistics Revolving Credit Facility, due August 2013 [Member]	'
Outstanding borrowings	$26

Redeemable_Preferred_Units_Det

Redeemable Preferred Units (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2011
Aggregate liquidation preference	'	$300	'
Preferrred Units Issued Stated Price	'	$100	'
ETE Preferred Units [Member]	'	'	'
Quarterly cash distribution, per preferred unit	$2	'	'
Preferred Units Premium Percentage Used For Conversion	'	10.00%	'
Premium Percentage Used For Conversion Of Preferred Units	'	25.00%	'
Discretional Percentage Conversion Rate Based On Issue Price	'	50.00%	'
Preferred units carrying value non-cash adjustment	'	8	5
Preferred units, fair value	323	331	323
Regency Preferred Units [Member]	'	'	'
Quarterly cash distribution, per preferred unit	'	$0.45	'
Preferred units outstanding	4,371,586	4,371,586	4,371,586
Common units issued upon conversion	'	4,658,700	'
Subsidiary preferred unit mandatory redemption date	'	'9/2/2029	'
Mandatory redeemable price of units outstanding	71	73	71
Regency Mandatorily Redeemable Amount At Expiration [Member]	'	'	'
Mandatory redeemable price of units outstanding	'	$80	'

Redeemable_Preferred_Units_Sch

Redeemable Preferred Units Schedule Of Redeemable Preferred Units (Details) (Regency Preferred Units [Member], USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Regency Preferred Units [Member]	'	'
Preferred Units [Line Items]	'	'
Preferred Units, Outstanding	4,371,586	4,371,586
Preferred Units Redemption Amount	$73	$71
Accretion to Redemption Value, Adjustment	$2	'

Equity_Narrative_Details

Equity (Narrative) (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2008

Jul. 31, 2012

Nov. 30, 2011

Apr. 30, 2011

Aug. 31, 2010

Jan. 31, 2010

Dec. 31, 2012

Dec. 31, 2012

Mar. 31, 2012

Oct. 31, 2011

31-May-11

Aug. 31, 2010

Dec. 31, 2012

Dec. 31, 2012

Sep. 30, 2011

Dec. 31, 2012

Sep. 30, 2011

Dec. 31, 2012

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Lone Star L.L.C. [Member]

Lone Star L.L.C. [Member]

Lone Star L.L.C. [Member]

Lone Star L.L.C. [Member]

Class F Units [Member]

Distribution Reinvestment Plan [Member]

ETP [Member]

ETP [Member]

Regency [Member]

Regency [Member]

Class F Units Issued in Holdco Transaction

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

90,706,000

Common Units Issued Inconnection With The Equity Distribution Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

691,129

'

'

'

'

'

Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Limited Partners' Capital Account, Units Outstanding

279,955,608

222,972,708

222,941,172

222,898,248

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Limited Partner interest in the Partnership, percentage

99.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain from subsidiary issuances of common units

$80

$153

$352

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common units issued through public offering

'

'

'

'

15,525,000

[1]

15,237,500

[1]

14,202,500

[1]

10,925,000

[1]

9,775,000

[1]

'

'

12,650,000

[1]

11,500,000

[1]

8,500,001

[1]

17,537,500

[1]

'

'

'

'

'

'

Value of units issued during period through DRIP

'

'

'

'

'

'

'

'

'

'

43

'

'

'

'

'

'

'

'

'

'

Units issued during period through DRIP

'

'

'

'

'

'

'

'

'

'

1,038,825

'

'

'

'

'

'

'

'

'

'

Proceeds from issuance of common units

'

'

'

'

671

[2],[3]

660

[2],[3]

695

[2]

489

[2],[3]

424

[2],[3]

'

'

297

[2],[3]

232

[2],[3]

204

[2],[3]

400

[2],[3]

'

'

'

'

'

'

Equity Distribution Agreement, maximum aggregate value of common units sold

'

'

'

'

'

'

'

'

'

200

'

'

'

'

'

200

'

'

'

'

'

Subsidiary Interest in Joint Venture

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

70.00%

70.00%

30.00%

30.00%

'

Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$15

'

'

'

'

'

[1]

Number of Common Units includes the exercise of the overallotment options by the underwriters.

[2]

Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.

[3]

Proceeds were used to repay amounts outstanding under the ETP Credit Facility.

Equity_Change_In_ETE_Common_Un

Equity (Change In ETE Common Units) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2008
Number of Common Units, beginning of period	222,972,708	222,941,172	'	222,898,248
Issuance of restricted Common Units under long-term incentive plans	740	31,536	42,924	'
Number of Common Units, end of period	279,955,608	222,972,708	222,941,172	222,898,248
SUG Merger [Member]	'	'	'	'
Business Acquisition Units Acquired	'	'	0	'

Equity_Equity_Schedule_Of_Comm

Equity Equity (Schedule Of Common Units Sold In Public Offering) (Details) (ETP [Member], USD $)	1 Months Ended										12 Months Ended
In Millions, except Share data, unless otherwise specified	Jul. 31, 2012		Nov. 30, 2011		Apr. 30, 2011		Aug. 31, 2010		Jan. 31, 2010		Dec. 31, 2012
											Distribution Reinvestment Plan [Member]
Capital Unit [Line Items]	'		'		'		'		'		'
Common Units to be Issued Under Distribution Reinvestment Plan	'		'		'		'		'		5,750,000
Number of ETP Common Units	15,525,000	[1]	15,237,500	[1]	14,202,500	[1]	10,925,000	[1]	9,775,000	[1]	'
Price per ETP Unit	$44.57		$44.67		$50.52		$46.22		$44.72		'
Net Proceeds	$671	[2],[3]	$660	[2],[3]	$695	[2]	$489	[2],[3]	$424	[2],[3]	'
[1]	Number of Common Units includes the exercise of the overallotment options by the underwriters.
[2]	Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.
[3]	Proceeds were used to repay amounts outstanding under the ETP Credit Facility.

Equity_Quarterly_Distributions

Equity (Quarterly Distributions Of Available Cash) (Details) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, except Per Share data, unless otherwise specified

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2009

Sep. 30, 2009

Jun. 30, 2009

Mar. 31, 2009

Dec. 31, 2008

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2009

Sep. 30, 2009

Jun. 30, 2009

Mar. 31, 2009

Dec. 31, 2008

Dec. 31, 2012

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Dec. 31, 2012

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

Parent Company [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

Record Date

'

'

'

'

6-Nov-12

6-Aug-12

4-May-12

7-Feb-12

4-Nov-11

5-Aug-11

6-May-11

7-Feb-11

8-Nov-10

9-Aug-10

7-May-10

8-Feb-10

'

'

6-Nov-12

6-Aug-12

4-May-12

7-Feb-12

4-Nov-11

5-Aug-11

6-May-11

7-Feb-11

8-Nov-10

9-Aug-10

7-May-10

8-Feb-10

'

'

6-Nov-12

6-Aug-12

7-May-12

6-Feb-12

7-Nov-11

5-Aug-11

6-May-11

7-Feb-11

5-Nov-10

6-Aug-10

'

Payment Date

'

'

'

'

16-Nov-12

17-Aug-12

18-May-12

17-Feb-12

18-Nov-11

19-Aug-11

19-May-11

18-Feb-11

19-Nov-10

19-Aug-10

19-May-10

19-Feb-10

'

'

14-Nov-12

14-Aug-12

15-May-12

14-Feb-12

14-Nov-11

15-Aug-11

16-May-11

14-Feb-11

15-Nov-10

16-Aug-10

17-May-10

15-Feb-10

'

'

14-Nov-12

14-Aug-12

14-May-12

13-Feb-12

14-Nov-11

12-Aug-11

13-May-11

14-Feb-11

12-Nov-10

13-Aug-10

'

Distributions paid, rate per unit

'

'

'

$0.64

$0.63

$0.63

$0.63

$0.63

$0.63

$0.63

$0.56

$0.54

$0.54

$0.54

$0.54

$0.54

$2.54

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$0.89

$3.58

$0.46

$0.46

$0.46

$0.46

$0.46

$0.46

$0.45

$0.45

$0.45

$0.45

$0.45

$1.84

Partners' Capital Account, Distributions

$666

$779

$483

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity_Accumulated_Other_Compr

Equity (Accumulated Other Comprehensive Income) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Partners' Capital Notes [Abstract]	'	'
Net gains on commodity related hedges	($3)	$2
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	-10	0
AOCI attributable to equity method investments	-9	0
Subtotal	-22	2
Amounts attributable to noncontrolling interest	10	-1
Total AOCI included in partners' capital, net of tax	($12)	$1

Equity_Schedule_of_Common_Unit

Equity Schedule of Common Units Sold in Offerings (Details) (USD $)

0 Months Ended

1 Months Ended

In Millions, except Share data, unless otherwise specified

Mar. 31, 2012

Oct. 31, 2011

31-May-11

Aug. 31, 2010

Jul. 31, 2012

Nov. 30, 2011

Apr. 30, 2011

Aug. 31, 2010

Jan. 31, 2010

Regency [Member]

Regency [Member]

Regency [Member]

Regency [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

ETP [Member]

Class of Stock [Line Items]

'

'

'

'

'

'

'

'

'

Common units issued through public offering

12,650,000

[1]

11,500,000

[1]

8,500,001

[1]

17,537,500

[1]

15,525,000

[1]

15,237,500

[1]

14,202,500

[1]

10,925,000

[1]

9,775,000

[1]

Price per Unit

$24.47

$20.92

'

$23.80

$44.57

$44.67

$50.52

$46.22

$44.72

Proceeds from issuance of common units

$297

[2],[3]

$232

[2],[3]

$204

[2],[3]

$400

[2],[3]

$671

[2],[3]

$660

[2],[3]

$695

[2]

$489

[2],[3]

$424

[2],[3]

[1]

Number of Common Units includes the exercise of the overallotment options by the underwriters.

[2]

Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.

[3]

Proceeds were used to repay amounts outstanding under the ETP Credit Facility.

Equity_Tax_amounts_in_componen

Equity Tax amounts in components of other comprehensive income (loss) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Other Comprehensive Income Loss Commodity Hedges Tax	$2	$0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax	5	0
Other Comprehensive Income (Loss), Tax	$7	$0

UnitBased_Compensation_Plans_D

Unit-Based Compensation Plans (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Affiliated Entity [Member]	'	'	'
Vesting Period	'5 years 0 months 0 days	'	'
Percentage Of Units Vesting In Current Year	20.00%	'	'
ETE Long-Term Incentive Plan [Member]	'	'	'
Preferred Units, Authorized	3,000,000	'	'
Units Remaining To Be Awarded	2,852,936	'	'
Unvested awards	740	'	'
Units Vested In Period	'	28,325	'
Fair Value Of Units As Of The Vesting Date	'	$1	'
Preferred Units, Outstanding	'	54,972	'
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	1	'	'
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	'1 year 11 months 0 days	'	'
ETP Unit-Based Compensation Plans [Member]	'	'	'
Unvested awards	1,859,159	2,563,709	'
Grant Date Fair Value Per Unit	$46.95	$46.37	'
Vesting Period	'5 years 0 months 0 days	'	'
Percentage Of Units Vesting In Current Year	20.00%	'	'
Units Vested In Period	-647,498	'	'
Fair Value Of Units As Of The Vesting Date	29	27	17
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	51	'	'
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	'1 year 9 months 0 days	'	'
Granted unvested awards	$43.93	$48.35	$49.82
Preferred units carrying value non-cash adjustment	1	2	4
Regency Common Unit Options [Member]	'	'	'
Unvested awards	0	'	'
Exercisable at the end of the period, Units	156,550	'	'
Options, Outstanding, Weighted Average Exercise Price	$21.96	'	'
Regency Phantom Units [Member]	'	'	'
Unvested awards	1,226,542	'	'
Grant Date Fair Value Per Unit	$23.22	'	'
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	26	'	'
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	'5 years 0 months 0 days	'	'
ETE Common Units [Member]	'	'	'
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$1	'	'
Common Units Outstanding	90,000	'	'
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	'0 years 7 months 0 days	'	'
Regency [Member]	'	'	'
Conversion Of Phantom Units To Common Units	252,630	'	'

UnitBased_Compensation_Plans_U1

Unit-Based Compensation Plans Unit-Based Compensation Plans (Schedule of ETP awards granted to employees and non-employee directors) (Details) (Details) (ETP Unit-Based Compensation Plans [Member], USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
ETP Unit-Based Compensation Plans [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Unvested awards	1,859,159	2,563,709	'
Weighted Average Grant-Date Fair Value Per ETP Unit	$46.95	$46.37	'
Awards granted	289,930	'	'
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$43.93	$48.35	$49.82
Awards vested	-647,498	'	'
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards vested	$44.58	'	'
Awards forfeited	-346,982	'	'
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards forfeited	$44.58	'	'

UnitBased_Compensation_Plans_S

Unit-Based Compensation Plans Sunoco Logistics Schedule of Unit Based Compensation (Details) (Sunoco Logistics [Member], USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012
Sunoco Logistics [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Units Remaining To Be Awarded	900,000
Unvested awards	427,610
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$10
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	'2 years 6 months

Income_Taxes_Narrative_Details

Income Taxes Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Operating Loss Carryforwards [Line Items]	'	'
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$24	'
Operating Loss Carryforwards	368	'
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	270	4
Valuation allowance for state net operating loss carryforwards, net of federal income tax effects	-94	-3
Valuation Allowance, Deferred Tax Asset, Change in Amount	1	'
Amount of Deferred Gain Challenged by IRS	545	'
Deferred Gain Associated with Like Kind Exchange	690	'
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax	16	'
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	5	'
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Other Information	'3	'
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	1	'
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	5	'
Expiring in 2028 [Member]	'	'
Operating Loss Carryforwards [Line Items]	'	'
Operating Loss Carryforwards	1	'
Expiring in 2029 [Member]	'	'
Operating Loss Carryforwards [Line Items]	'	'
Operating Loss Carryforwards	3	'
Expiring in 2030 [Member]	'	'
Operating Loss Carryforwards [Line Items]	'	'
Operating Loss Carryforwards	18	'
Expiring in 2031 [Member]	'	'
Operating Loss Carryforwards [Line Items]	'	'
Operating Loss Carryforwards	40	'
Expiring in 2032 [Member]	'	'
Operating Loss Carryforwards [Line Items]	'	'
Operating Loss Carryforwards	306	'
Expiring 2013 to 2032 [Member]	'	'
Operating Loss Carryforwards [Line Items]	'	'
Operating Loss Carryforwards	104	'
Holdco [Member]	'	'
Operating Loss Carryforwards [Line Items]	'	'
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	37	'
Federal Net Operating Loss Benefit [Member]	'	'
Operating Loss Carryforwards [Line Items]	'	'
Valuation allowance for state net operating loss carryforwards, net of federal income tax effects	-4	'
State Net Operating Loss Benefits [Member]	'	'
Operating Loss Carryforwards [Line Items]	'	'
Valuation allowance for state net operating loss carryforwards, net of federal income tax effects	($90)	'

Income_Taxes_Components_of_Inc

Income Taxes Components of Income Tax (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Abstract]	'	'	'
Federal	($3)	($1)	$1
State	6	17	9
Total	3	16	10
Federal	41	0	3
State	10	1	1
Total	51	1	4
Total income tax expense from continuing operations	$54	$17	$14

Income_Taxes_Reconciliation_of

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate	35.00%	'	'
Income tax expense (benefit) at U.S. statutory rate of 35%	($4)	'	'
Nondeductible executive compensation	28	'	'
State income taxes (net of federal income tax effects)	11	'	'
Other	19	'	'
Income Tax Expense (Benefit), Continuing Operations	54	17	14
Consolidation, Eliminations [Member]	'	'	'
Income tax expense (benefit) at U.S. statutory rate of 35%	0	'	'
Nondeductible executive compensation	0	'	'
State income taxes (net of federal income tax effects)	2	'	'
Other	0	'	'
Income Tax Expense (Benefit), Continuing Operations	2	'	'
ETP Holdco [Member]	'	'	'
Income tax expense (benefit) at U.S. statutory rate of 35%	-1	'	'
Nondeductible executive compensation	28	'	'
State income taxes (net of federal income tax effects)	9	'	'
Other	17	'	'
Income Tax Expense (Benefit), Continuing Operations	53	'	'
All Other Subsidiaries [Member]	'	'	'
Income tax expense (benefit) at U.S. statutory rate of 35%	-3	'	'
Nondeductible executive compensation	0	'	'
State income taxes (net of federal income tax effects)	0	'	'
Other	2	'	'
Income Tax Expense (Benefit), Continuing Operations	($1)	'	'

Income_Taxes_Effects_of_Tempor

Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Effects of Temporary Differences that Comprise Net Deferred Income Tax Liability [Abstract]	'	'
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	$270	$4
Pension and other postretirement benefits	127	0
Long term debt	117	0
Net deferred income tax assets	710	5
Valuation allowance for state net operating loss carryforwards, net of federal income tax effects	-94	-3
Other	290	4
Deferred Tax Assets, Gross	804	8
Properties, plants and equipment	-2,026	-147
Inventory	-516	0
Investments in unconsolidated affiliates	-1,543	-72
Deferred Tax Liabilities, Intangible Assets	-192	0
Other	-129	0
Deferred Tax Liabilities	-4,406	-219
Deferred Tax Liabilities, Gross	-3,696	-214
Deferred Tax Liabilities, Net, Current	-130	3
Deferred Tax Liabilities, Net, Noncurrent	$3,566	$217

Income_Taxes_Components_of_Net

Income Taxes Components of Net Deferred Tax Liability (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Deferred Tax Liability Not Recognized [Line Items]	'	'	'
Valuation allowance	$94,000,000	$3,000,000	'
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	270,000,000	4,000,000	'
Increase in Tax Liability Attributable to Southern Union	-1,428,000,000	'	'
Increase in Tax Liability Attributable to Sunoco Acquisition	-1,989,000,000	'	'
Tax Provision (including discontinued operations)	-62,000,000	'	'
Deferred income taxes	-51,000,000	-1,000,000	-4,000,000
Deferred Tax Liabilities, Gross	-3,696,000,000	-214,000,000	'
Net deferred income tax liability	710,000,000	5,000,000	'
Other Deferred Tax Liability [Member]	'	'	'
Deferred Tax Liability Not Recognized [Line Items]	'	'	'
Deferred income taxes	$3,000,000	'	'

Income_Taxes_Changes_in_Unreco

Income Taxes Changes in Unrecognized Tax Benefits (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Changes in Unrecognized Tax Benefits [Abstract]	'	'	'
Balance at beginning of year	$2	$2	$1
Additions attributable to tax positions taken in the current year	28	0	0
Additions attributable to tax positions taken in prior years	0	1	0
Reductions attributable to tax positions taken in prior years	0	0	1
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations	-3	-1	0
Balance at end of year	27	2	2
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$24	'	'

Regulatory_Matters_Commitments2

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

Jul. 07, 2011

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Jan. 12, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2011

Jan. 12, 2012

Jan. 12, 2012

Dec. 31, 2012

Dec. 31, 2012

AmeriGas [Member]

FGT [Member]

Related To Deductibles [Member]

Related To Deductibles [Member]

6.75% Senior Notes Due 2020 [Member]

7.00% Senior Notes Due 2022 [Member]

Jal 3 Facility [Member]

Jal 4 Facility [Member]

AmeriGas Finance LLC [Member]

AmeriGas Finance LLC [Member]

Payments for Environmental Liabilities

'

'

$12,000,000

'

'

'

'

'

'

'

'

'

'

Aggregate principal amount

'

'

'

'

'

'

'

'

'

550,000,000

1,000,000,000

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

'

6.75%

7.00%

'

'

Proceeds from (Repayments of) Related Party Debt

'

'

'

'

'

1,500,000,000

'

'

'

'

'

'

'

Maximum lease expiration year

'

'

31-Dec-56

'

'

'

'

'

'

'

'

'

'

Operating leases rent expense

'

'

59,700,000

29,000,000

24,000,000

'

'

'

'

'

'

'

'

Accrual for loss contingency

'

'

'

'

'

'

'

15,000,000

18,000,000

'

'

'

'

Total environmental liabilities

'

212,000,000

212,000,000

14,000,000

'

'

'

'

'

'

'

'

'

Legal Fees

19,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Legal Settlements

'

'

'

'

'

'

83,000,000

'

'

'

'

'

'

Interest Awarded

'

'

'

'

'

'

8,000,000

'

'

'

'

'

'

Alleged Violations, Air Regulation, Cost

'

'

'

'

'

'

'

'

'

'

'

1,000,000

7,000,000

Operating Leases, Rent Expense, Contingent Rentals

'

$6,000,000

'

'

'

'

'

'

'

'

'

'

'

Regulatory_Matters_Commitments3

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Schedule of Future Minimum Rental Payments for Operating Leases) (Details) (USD $)	Dec. 31, 2012
In Millions, unless otherwise specified
Operating Leased Assets [Line Items]	'
2013	$92
2014	82
2015	79
2016	64
2017	52
Thereafter	462
Total Future Rent Payments	831
Future Rental Income	-64
Net Future Rental Payments	$767

Regulatory_Matters_Commitments4

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Environmental Remediation Obligations [Abstract]	'	'
Current	$46	$4
Non-current	166	10
Total environmental liabilities	$212	$14

Price_Risk_Management_Assets_A2

Price Risk Management Assets And Liabilities (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended
	Sep. 30, 2010	Dec. 31, 2012	Dec. 31, 2011
		years
Asset Derivatives	'	$213,000,000	$346,000,000
Derivative Liability, Fair Value, Gross Liability	'	430,000,000	424,000,000
Option Premiums	'	7,000,000	'
Swap maturity term (years)	'	10	'
Deposits with counterparties	'	41,000,000	66,000,000
Payment To Terminate Non Hedged Interest Rate Swaps	102,000,000	'	'
ETP [Member]	'	'	'
Expected gains (losses) related to commodity derivatives to be reclassified into earnings over next year related to amounts currently reported in AOCI	'	-6,000,000	'
Regency [Member]	'	'	'
Expected gains (losses) related to commodity derivatives to be reclassified into earnings over next year related to amounts currently reported in AOCI	'	1,000,000	'
Southern Union [Member]	'	'	'
Derivative, Net Liability Position, Aggregate Fair Value	'	4,000,000	'
Segment, Discontinued Operations [Member]	'	'	'
Asset Derivatives	'	1,000,000	'
Derivative Liability, Fair Value, Gross Liability	'	-8,000,000	'
Interest Rate Derivatives [Member] | ETE [Member]	'	'	'
Notional Amount of Derivatives	1,500,000,000	'	'
Interest Expense [Member] | Interest Rate Derivatives [Member] | ETE [Member]	'	'	'
Cash Flow Hedge Loss Reclassified to Interest Expense	$66,000,000	'	'

Price_Risk_Management_Assets_A3

Price Risk Management Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)	Dec. 31, 2012	Dec. 31, 2011
	MMbtu	MMbtu
Mark-To-Market Derivatives [Member] | Power - Futures [Member] | ETP [Member]	'	'
Notional Volume	-1,509,300	0
Maturity	'2013	'
Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC (MMBtu) [Member] | ETP [Member]	'	'
Notional Volume	-83,292,500	92,370,000
Maturity	'2013	'
Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures (MMBtu) [Member] | ETP [Member]	'	'
Notional Volume	27,077,500	797,500
Maturity	'2013	'2012
Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures (MMBtu) [Member] | Regency [Member]	'	'
Notional Volume	8,395,000	'
Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Forward Physical Contracts (MMBtu) [Member] | ETP [Member]	'	'
Notional Volume	11,689,855	-10,672,028
Maturity	'	'2012
Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Options - Calls (MMBtu) [Member] | ETP [Member]	'	'
Notional Volume	0	0
Maturity	'2013	'
Mark-To-Market Derivatives [Member] | NGL [Member] | Forwards/Swaps [Member] | ETP [Member]	'	'
Notional Volume	-30,000	'
Maturity	'2013	'
Mark-To-Market Derivatives [Member] | Refined Products [Member] | Forwards/Swaps [Member] | ETP [Member]	'	'
Notional Volume	-666,000	'
Maturity	'2013	'
Mark-To-Market Derivatives [Member] | Power - Forward Swaps [Member] | Forwards (Thousand Megawatt) [Member] | ETP [Member]	'	'
Notional Volume	19,650	0
Maturity	'2013	'
Mark-To-Market Derivatives [Member] | Power - Option - Calls [Member] | ETP [Member]	'	'
Notional Volume	1,656,400	0
Maturity	'2013	'
Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | ETP [Member]	'	'
Notional Volume	0	38,766,000
Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | Regency [Member]	'	'
Notional Volume	3,318,000	'
Mark-To-Market Derivatives [Member] | Natural Gas Liquids [Member] | Forwards/Swaps | Regency [Member]	'	'
Notional Volume	243,000	'
Mark-To-Market Derivatives [Member] | Natural Gas Liquids [Member] | Options — Puts | Regency [Member]	'	'
Notional Volume	0	110,000
Maturity	'	'2012
Mark-To-Market Derivatives [Member] | WTI Crude Oil [Member] | Forwards/Swaps | Regency [Member]	'	'
Notional Volume	356,000	'
Fair Value Hedging Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]	'	'
Notional Volume	-18,655,000	-28,752,500
Maturity	'2013	'2012
Fair Value Hedging Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures (MMBtu) [Member] | ETP [Member]	'	'
Notional Volume	-44,272,500	-45,822,500
Maturity	'2013	'2012
Fair Value Hedging Derivatives [Member] | Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | ETP [Member]	'	'
Notional Volume	44,272,500	45,822,500
Maturity	'2013	'2012
Cash Flow Hedging Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures (MMBtu) [Member] | ETP [Member]	'	'
Notional Volume	-8,212,500	0
Maturity	'2013	'
Cash Flow Hedging Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures (MMBtu) [Member] | Regency [Member]	'	'
Notional Volume	'	2,198,000
Maturity	'	'2012
Cash Flow Hedging Derivatives [Member] | Natural Gas [Member] | Options - Puts (MMBtu) [Member] | ETP [Member]	'	'
Notional Volume	0	3,600,000
Maturity	'	'2012
Cash Flow Hedging Derivatives [Member] | Natural Gas [Member] | Options - Calls (MMBtu) [Member] | ETP [Member]	'	'
Notional Volume	0	-3,600,000
Maturity	'	'2012
Cash Flow Hedging Derivatives [Member] | NGL [Member] | Forwards/Swaps [Member] | ETP [Member]	'	'
Notional Volume	-930,000	'
Maturity	'2013	'
Cash Flow Hedging Derivatives [Member] | Refined Products [Member] | Forwards/Swaps [Member] | ETP [Member]	'	'
Notional Volume	-98,000	0
Maturity	'2013	'
Cash Flow Hedging Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | ETP [Member]	'	'
Notional Volume	'	0
Cash Flow Hedging Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | Regency [Member]	'	'
Notional Volume	'	11,802,000
Maturity	'2013	'
Cash Flow Hedging Derivatives [Member] | Natural Gas Liquids [Member] | Forwards/Swaps | Regency [Member]	'	'
Notional Volume	'	533,000
Cash Flow Hedging Derivatives [Member] | WTI Crude Oil [Member] | Forwards/Swaps | Regency [Member]	'	'
Notional Volume	'	350,000
Maturity	'2014	'
Maximum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC (MMBtu) [Member] | ETP [Member]	'	'
Maturity	'	'2013
Maximum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures (MMBtu) [Member] | Regency [Member]	'	'
Maturity	'2014	'
Maximum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Forward Physical Contracts (MMBtu) [Member] | ETP [Member]	'	'
Maturity	'2014	'
Maximum [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | ETP [Member]	'	'
Maturity	'	'2013
Maximum [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | Regency [Member]	'	'
Maturity	'2014	'
Maximum [Member] | Cash Flow Hedging Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures (MMBtu) [Member] | Regency [Member]	'	'
Maturity	'	'2013
Maximum [Member] | Cash Flow Hedging Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | Regency [Member]	'	'
Maturity	'	'2013
Maximum [Member] | Cash Flow Hedging Derivatives [Member] | WTI Crude Oil [Member] | Forwards/Swaps | Regency [Member]	'	'
Maturity	'	'2014
Minimum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC (MMBtu) [Member] | ETP [Member]	'	'
Maturity	'	'2012
Minimum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures (MMBtu) [Member] | Regency [Member]	'	'
Maturity	'2013	'
Minimum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Forward Physical Contracts (MMBtu) [Member] | ETP [Member]	'	'
Maturity	'2013	'
Minimum [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | ETP [Member]	'	'
Maturity	'	'2012
Minimum [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | Regency [Member]	'	'
Maturity	'2013	'
Minimum [Member] | Cash Flow Hedging Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures (MMBtu) [Member] | Regency [Member]	'	'
Maturity	'	'2012
Minimum [Member] | Cash Flow Hedging Derivatives [Member] | Propane [Member] | Forwards/Swaps (Gallons) [Member] | Regency [Member]	'	'
Maturity	'	'2012
Minimum [Member] | Cash Flow Hedging Derivatives [Member] | WTI Crude Oil [Member] | Forwards/Swaps | Regency [Member]	'	'
Maturity	'	'2012
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]	'	'
Notional Volume	-30,980,000	-151,260,000
Trading [Member] | Maximum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]	'	'
Maturity	'2014	'2013
Trading [Member] | Minimum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]	'	'
Maturity	'2013	'2012
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]	'	'
Notional Volume	150,000	-61,420,000
Maturity	'2013	'
Non Trading [Member] | Maximum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]	'	'
Maturity	'	'2013
Non Trading [Member] | Minimum [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ETP [Member]	'	'
Maturity	'	'2012

Price_Risk_Management_Assets_A4

Price Risk Management Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) (Interest Rate Derivatives [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
March 2017 | Parent Company [Member]	'	'
Notional Amount	$500	$0
Type	'Pay a fixed rate of 1.25% and receive a floating rate	'
May 2012 (2) | ETP [Member]	'	'
Notional Amount	0	350
Type	'Forward starting to pay a fixed rate of 2.59% and receive a floating rate	'
August 2012 [Member] | ETP [Member]	'	'
Notional Amount	0	500
Type	'Forward starting to pay a fixed rate of 3.51% and receive a floating rate	'
July 2013 [Member] | ETP [Member]	'	'
Notional Amount	400	300
Type	'Forward starting to pay a fixed rate of 4.02% and receive a floating rate	'
July 2018 [Member] | ETP [Member]	'	'
Notional Amount	600	500
Type	'Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	'
April 2012 [Member] | Regency [Member]	'	'
Notional Amount	'	250
Type	'Pay a fixed rate of 1.325% and receive a floating rate	'
April 2012 [Member] | Southern Union [Member]	'	'
Notional Amount	0	'
July 2014 [Member] | ETP [Member]	'	'
Notional Amount	400	0
Type	'Forward starting to pay a fixed rate of 4.26% and receive a floating rate	'
November 2016 [Member] | Southern Union [Member]	'	'
Notional Amount	75	'
Type	'Pay a fixed rate of 2.913% and receive a floating rate	'
November 2021 [Member] | Southern Union [Member]	'	'
Notional Amount	$450	'
Type	'Pay a fixed rate of 3.746% and receive a floating rate	'

Price_Risk_Management_Assets_A5

Price Risk Management Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Asset Derivatives	$213	$346
Liability Derivatives	-430	-424
Designated as Hedging Instrument [Member]	'	'
Asset Derivatives	8	82
Liability Derivatives	-10	-11
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]	'	'
Asset Derivatives	8	77
Liability Derivatives	-10	-1
Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]	'	'
Asset Derivatives	0	5
Liability Derivatives	0	-10
Not Designated as Hedging Instrument [Member]	'	'
Asset Derivatives	205	264
Liability Derivatives	-420	-413
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]	'	'
Asset Derivatives	110	227
Liability Derivatives	-116	-251
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]	'	'
Asset Derivatives	40	1
Liability Derivatives	-44	-5
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]	'	'
Asset Derivatives	55	36
Liability Derivatives	-235	-118
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]	'	'
Asset Derivatives	0	0
Liability Derivatives	($25)	($39)

Price_Risk_Management_Assets_A6

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$8	$6	$20
Commodity Derivatives [Member]	'	'	'
Change in Value Recognized in OCI on Derivatives (Effective Portion)	8	6	50
Interest Rate Derivatives [Member]	'	'	'
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$0	$0	($30)

Price_Risk_Management_Assets_A7

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$14	$19	($50)
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	54	34	16
Amount of Gain/(Loss) Recognized in Income on Derivatives	40	-81	-56
Commodity Derivatives [Member] | Cost of Products Sold [Member]	'	'	'
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	14	19	37
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	54	34	16
Interest Rate Derivatives [Member] | Interest Expense [Member]	'	'	'
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	0	0	-87
Interest Rate Derivatives [Member] | Losses On Non-Hedged Interest Rate Derivatives [Member]	'	'	'
Amount of Gain/(Loss) Recognized in Income on Derivatives	-19	-78	-52
Embedded Derivatives [Member] | Other Income (Expenses) [Member]	'	'	'
Amount of Gain/(Loss) Recognized in Income on Derivatives	14	18	-8
Non Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]	'	'	'
Amount of Gain/(Loss) Recognized in Income on Derivatives	26	9	4
Non Trading [Member] | Commodity Derivatives [Member] | Deferred Gas Purchases [Member]	'	'	'
Amount of Gain/(Loss) Recognized in Income on Derivatives	26	0	0
Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]	'	'	'
Amount of Gain/(Loss) Recognized in Income on Derivatives	($7)	($30)	$0

Retirement_Benefits_Narrative_

Retirement Benefits (Narrative) (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Retirement Benefits [Line Items]	'	'	'	'
Pretax curtailment gain	$75	'	'	'
Noncurrent refund liability	60	'	'	'
Gain on curtailment of other postretirement benefit plans	'	-15	0	0
Contributions by employer, defined contribution plan	'	11	'	'
ETP [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Contributions by employer, defined contribution plan	'	'	14	10
Regency [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Contributions by employer, defined contribution plan	'	'	2	'
Sunoco [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent	200	200	'	'
Savings Plan [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Defined Contribution Plan, Cost Recognized	6	'	'	'
Supplemental Employee Retirement Plans, Defined Benefit [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Defined Contribution Plan, Cost Recognized	2	'	'	'
Pension Benefits | Southern Union [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Large Cap US Equitiies	36.00%	36.00%	'	'
Fixed Income Securities	54.00%	54.00%	'	'
Other Investments - Plan Asset Allocation	10.00%	10.00%	'	'
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	18	18	'	'
Pension Benefits | Equity [Member] | Southern Union [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	'	25.00%	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	'	70.00%	'	'
Pension Benefits | Fixed Income Investments [Member] | Southern Union [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	'	15.00%	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	'	35.00%	'	'
Pension Benefits | Alternative Assets [Member] | Southern Union [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	'	10.00%	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	'	35.00%	'	'
Pension Benefits | Cash [Member] | Southern Union [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Defined Benefit Plan, Target Allocation Percentage, Cash Minimum	'	0.00%	'	'
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum	'	10.00%	'	'
Other Postretirement Benefits	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Gain on curtailment of other postretirement benefit plans	'	15	'	'
Other Postretirement Benefits | Southern Union [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Large Cap US Equitiies	19.00%	19.00%	'	'
Fixed Income Securities	74.00%	74.00%	'	'
Cash Fund Investments	4.00%	4.00%	'	'
Other Investments - Plan Asset Allocation	3.00%	3.00%	'	'
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$8	$8	'	'
Other Postretirement Benefits | Equity [Member] | Southern Union [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	'	25.00%	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	'	35.00%	'	'
Other Postretirement Benefits | Fixed Income Investments [Member] | Southern Union [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	'	65.00%	'	'
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	'	75.00%	'	'
Other Postretirement Benefits | Cash [Member] | Southern Union [Member]	'	'	'	'
Retirement Benefits [Line Items]	'	'	'	'
Defined Benefit Plan, Target Allocation Percentage, Cash Minimum	'	0.00%	'	'
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum	'	10.00%	'	'

Retirement_Benefits_Southern_U

Retirement Benefits Southern Union Obligations and Funded Status (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Mar. 25, 2012
Pension Benefits	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Benefit Obligation	$1,195	$1,257
Defined Benefit Plan, Service Cost	3	'
Defined Benefit Plan, Interest Cost	15	'
Defined Benefit Plan, Plan Amendments	0	'
Defined Benefit Plan, Benefits Paid	-71	'
Defined Benefit Plan, Curtailments	0	'
Actuarial Loss and Other	-9	'
Defined Benefit Plan, Fair Value of Plan Assets	906	941
Defined Benefit Plan, Actual Return on Plan Assets	22	'
Defined Benefit Plan, Contributions by Employer	14	'
Defined Benefit Plan, Funded Status of Plan	289	'
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	0	'
Defined Benefit Plan, Amortization of Net Gains (Losses)	-1	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	0	'
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	15	'
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	274	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet	-289	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	-1	'
Other Postretirement Benefits	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Benefit Obligation	296	359
Defined Benefit Plan, Service Cost	1	'
Defined Benefit Plan, Interest Cost	3	'
Defined Benefit Plan, Plan Amendments	17	'
Defined Benefit Plan, Benefits Paid	-8	'
Defined Benefit Plan, Curtailments	-80	'
Actuarial Loss and Other	4	'
Defined Benefit Plan, Fair Value of Plan Assets	312	306
Defined Benefit Plan, Actual Return on Plan Assets	5	'
Defined Benefit Plan, Contributions by Employer	9	'
Defined Benefit Plan, Funded Status of Plan	-16	'
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	59	'
Defined Benefit Plan, Amortization of Net Gains (Losses)	-1	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	16	'
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	2	'
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	41	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet	16	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$15	'

Retirement_Benefits_Southern_U1

Retirement Benefits Southern Union Accumulated Benefit Obligation In Excess of Plan Assets (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Pension Benefits	'
Defined Benefit Plan Disclosure [Line Items]	'
Defined Benefit Plan, Service Cost	$3
Defined Benefit Plan, Interest Cost	15
Defined Benefit Plan, Expected Return on Plan Assets	21
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	-2
Net periodic benefit cost subtotal	-1
Net Period Benefit Cost Regulatory Adjustment	9
Defined Benefit Plan, Net Periodic Benefit Cost	8
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation	1,195
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	1,179
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	906
Other Postretirement Benefits	'
Defined Benefit Plan Disclosure [Line Items]	'
Defined Benefit Plan, Service Cost	1
Defined Benefit Plan, Interest Cost	3
Defined Benefit Plan, Expected Return on Plan Assets	5
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0
Net periodic benefit cost subtotal	-16
Net Period Benefit Cost Regulatory Adjustment	2
Defined Benefit Plan, Net Periodic Benefit Cost	-14
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	225
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	$185

Retirement_Benefits_Southern_U2

Retirement Benefits Southern Union Benefit Assumptions (Details)	12 Months Ended
	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]	'
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	7.78%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	5.32%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	'2018
Pension Benefits	'
Defined Benefit Plan Disclosure [Line Items]	'
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	2.00%
Expected long term return on assets, tax exempt accounts	7.63%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.41%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.17%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.00%
Other Postretirement Benefits	'
Defined Benefit Plan Disclosure [Line Items]	'
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	2.00%
Expected long term return on assets, tax exempt accounts	7.00%
Expected long term return on assets, taxable accounts	4.50%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.39%

Retirement_Benefits_Schedule_o

Retirement Benefits (Schedule of benefit payments expected future service) (Details) (USD $)	Dec. 31, 2012
In Millions, unless otherwise specified
Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$254
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	105
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	98
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	87
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	82
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	328
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	38
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	34
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	33
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	32
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	30
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	107
Other Postretirement Benefits (Medicare Part D Subsidy Receipts) [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	1
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	1
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	1
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	1
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	1
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	$4

Retirement_Benefits_Fair_value

Retirement Benefits Fair value of plan assets (Details) (Pension Benefits, USD $)	Dec. 31, 2012	Mar. 25, 2012
In Millions, unless otherwise specified
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	$906	$941
Southern Union [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	906	'
Southern Union [Member] | Cash and Cash Equivalents [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	25	'
Southern Union [Member] | Mutual Fund [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	516	'
Southern Union [Member] | Fixed Income Securities [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	354	'
Southern Union [Member] | Hedge Funds, Multi-strategy [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	11	'
Level 1 [Member] | Southern Union [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	25	'
Level 1 [Member] | Southern Union [Member] | Cash and Cash Equivalents [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	25	'
Level 1 [Member] | Southern Union [Member] | Mutual Fund [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Level 1 [Member] | Southern Union [Member] | Fixed Income Securities [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Level 1 [Member] | Southern Union [Member] | Hedge Funds, Multi-strategy [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Level 2 [Member] | Southern Union [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	798	'
Level 2 [Member] | Southern Union [Member] | Cash and Cash Equivalents [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Level 2 [Member] | Southern Union [Member] | Mutual Fund [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	433	'
Level 2 [Member] | Southern Union [Member] | Fixed Income Securities [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	354	'
Level 2 [Member] | Southern Union [Member] | Hedge Funds, Multi-strategy [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	11	'
Fair Value, Inputs, Level 3 [Member] | Southern Union [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	83	'
Fair Value, Inputs, Level 3 [Member] | Southern Union [Member] | Cash and Cash Equivalents [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Fair Value, Inputs, Level 3 [Member] | Southern Union [Member] | Mutual Fund [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	83	'
Fair Value, Inputs, Level 3 [Member] | Southern Union [Member] | Fixed Income Securities [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Fair Value, Inputs, Level 3 [Member] | Southern Union [Member] | Hedge Funds, Multi-strategy [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	$0	'

Recovered_Sheet13

Retirement Benefits (schedule of fair value of the other postretirement plan assets by asset category) (Details) (Other Postretirement Benefits, USD $)	Dec. 31, 2012	Mar. 25, 2012
In Millions, unless otherwise specified
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	$312	$306
Southern Union [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	312	'
Southern Union [Member] | Cash and Cash Equivalents [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	7	'
Southern Union [Member] | Mutual Fund [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	147	'
Southern Union [Member] | Fixed Income Securities [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	158	'
Level 1 [Member] | Southern Union [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	133	'
Level 1 [Member] | Southern Union [Member] | Cash and Cash Equivalents [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	7	'
Level 1 [Member] | Southern Union [Member] | Mutual Fund [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	126	'
Level 1 [Member] | Southern Union [Member] | Fixed Income Securities [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Level 2 [Member] | Southern Union [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	179	'
Level 2 [Member] | Southern Union [Member] | Cash and Cash Equivalents [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Level 2 [Member] | Southern Union [Member] | Mutual Fund [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	21	'
Level 2 [Member] | Southern Union [Member] | Fixed Income Securities [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	158	'
Fair Value, Inputs, Level 3 [Member] | Southern Union [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Fair Value, Inputs, Level 3 [Member] | Southern Union [Member] | Cash and Cash Equivalents [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Fair Value, Inputs, Level 3 [Member] | Southern Union [Member] | Mutual Fund [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	0	'
Fair Value, Inputs, Level 3 [Member] | Southern Union [Member] | Fixed Income Securities [Member]	'	'
Fair Value of Plan Assets [Line Items]	'	'
Defined Benefit Plan, Fair Value of Plan Assets	$0	'

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
		Enterprise [Member]	Enterprise [Member]
General administrative expenses reimbursed	'	$507	$444
Revenue	$190	$1,040	$697

Reportable_Segments_Operating_

Reportable Segments (Operating Segments) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues	$11,313	$2,107	$1,875	$1,669	$2,166	$2,084	$1,963	$1,977	$16,964	$8,190	$6,556
Depreciation and amortization	'	'	'	'	'	'	'	'	871	586	406
Interest expense, net of interest capitalized	'	'	'	'	'	'	'	'	1,018	740	625
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	212	117	65
Income tax benefit	'	'	'	'	'	'	'	'	54	17	14
Net income (loss)	272	-34	75	961	161	61	107	199	1,274	528	337
Cost of products sold	'	'	'	'	'	'	'	'	13,088	5,169	4,102
Investment In ETP [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from external customers	'	'	'	'	'	'	'	'	15,671	6,761	5,843
Intersegment revenues	'	'	'	'	'	'	'	'	31	38	0
Depreciation and amortization	'	'	'	'	'	'	'	'	656	405	317
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	142	26	12
Segment Reporting Information, Revenue for Reportable Segment	'	'	'	'	'	'	'	'	15,702	6,799	5,843
Cost of products sold	'	'	'	'	'	'	'	'	12,266	4,175	3,591
Investment In Regency [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from external customers	'	'	'	'	'	'	'	'	1,986	1,426	715
Intersegment revenues	'	'	'	'	'	'	'	'	14	8	1
Depreciation and amortization	'	'	'	'	'	'	'	'	252	169	76
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	105	120	54
Segment Reporting Information, Revenue for Reportable Segment	'	'	'	'	'	'	'	'	2,000	1,434	716
Cost of products sold	'	'	'	'	'	'	'	'	1,387	1,013	504
Adjustments and Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from external customers	'	'	'	'	'	'	'	'	-738	-43	-3
Depreciation and amortization	'	'	'	'	'	'	'	'	-51	0	0
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	-35	-29	-1
Cost of products sold	'	'	'	'	'	'	'	'	-565	-19	7
Corporate And Other Activities [Member]	'	'	'	'	'	'	'	'	'	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	$14	$12	$13

Reportable_Segments_Assets_Seg

Reportable Segments (Assets Segments)(Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Millions, unless otherwise specified
Assets	$48,904	$20,897	$17,678
Investment In ETP [Member]	'	'	'
Assets	43,230	15,519	12,450
Investment In Regency [Member]	'	'	'
Assets	8,123	5,568	4,770
Corporate And Other [Member]	'	'	'
Assets	707	470	469
Adjustments and Eliminations [Member]	'	'	'
Assets	($3,156)	($660)	($11)

Reporting_Segments_Additions_T

Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]	'	'	'
Segment Reporting Information, Expenditures for Additions to Long-Lived Assets	$3,493	$3,333	$3,538
Investment In ETP [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Segment Reporting Information, Expenditures for Additions to Long-Lived Assets	3,057	2,922	1,470
Investment in Regency [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Segment Reporting Information, Expenditures for Additions to Long-Lived Assets	560	411	2,068
Adjustments and Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Segment Reporting Information, Expenditures for Additions to Long-Lived Assets	-124	0	0
LDH Merger [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Segment Reporting Information, Expenditures for Additions to Long-Lived Assets	'	1,420	'
Regency Transactions [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Segment Reporting Information, Expenditures for Additions to Long-Lived Assets	'	'	$1,550

Reporting_Segments_Advances_To

Reporting Segments (Advances To And Investments In Affiliates Segments) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Millions, unless otherwise specified
Segment Reporting Information [Line Items]	'	'	'
Advance to and investments in affiliates:	$4,737	$1,497	$1
Investment In Regency [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Advance to and investments in affiliates:	2,214	1,925	1
Adjustments and Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Advance to and investments in affiliates:	($979)	($629)	$0

Reportable_Segments_Reportable

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]	'	'	'
Adjusted EBITDA	$3,105	$2,131	$1,738
Depreciation and amortization	-871	-586	-406
Interest expense, net of interest capitalized	-1,018	-740	-625
Bridge loan related fees	-62	0	0
Gain on deconsolidation of Propane Business	1,057	0	0
Losses on non-hedged interest rate derivatives	-19	-78	-52
Non-cash compensation expense	-47	-42	-31
Losses on non-hedged interest rate derivatives	10	7	-110
Gain (Loss) on Disposition of Assets	-4	-1	-5
Losses on extinguishments of debt	-123	0	-16
Gain on curtailment of other postretirement benefit plans	-15	0	0
Impairments of investments in affiliates	0	5	53
Inventory, LIFO Reserve, Effect on Income, Net	-75	0	0
Proportionate share of unconsolidated affiliates’ interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes	-435	-114	-71
Adjusted EBITDA related to discontinued operations	-99	-23	-19
Other, net	14	-7	-49
Income from continuing operations before income tax expense	1,437	548	359
Investment In ETP [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Adjusted EBITDA	2,744	1,781	1,541
Depreciation and amortization	-656	-405	-317
Corporate And Others [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Adjusted EBITDA	-52	-29	-21
Investment In Regency [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Adjusted EBITDA	525	422	218
Depreciation and amortization	-252	-169	-76
Corporate And Other Activities [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Depreciation and amortization	-14	-12	-13
Adjustments And Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Adjusted EBITDA	-112	-43	0
Depreciation and amortization	$51	$0	$0

Reportable_Segments_Equity_in_

Reportable Segments (Equity in earnings of unconsolidated affiliates) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]	'	'	'
Equity in earnings of unconsolidated affiliates	$212	$117	$65
Investment In ETP [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Equity in earnings of unconsolidated affiliates	142	26	12
Investment In Regency [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Equity in earnings of unconsolidated affiliates	105	120	54
Adjustments and Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Equity in earnings of unconsolidated affiliates	($35)	($29)	($1)

Reportable_Segments_Advances_t

Reportable Segments (Advances to and investments in affiliates) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Millions, unless otherwise specified
Segment Reporting Information [Line Items]	'	'	'
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	$4,737	$1,497	$1
Investment In ETP [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,502	201	0
Investment In Regency [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	2,214	1,925	1
Adjustments And Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	($979)	($629)	$0

Quarterly_Financial_Data_Unaud2

Quarterly Financial Data (Unaudited) (Schedule of Quarterly Financial Information) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues	$11,313	$2,107	$1,875	$1,669	$2,166	$2,084	$1,963	$1,977	$16,964	$8,190	$6,556
Gross margin	1,430	876	916	654	804	736	703	778	3,876	3,021	'
Operating income	452	358	367	183	339	272	263	363	1,360	1,237	1,044
Net income	272	-34	75	961	161	61	107	199	1,274	528	337
Income (loss) from continuing operations	'	'	'	'	'	'	'	'	1,383	531	345
Loss from discontinued operations	'	'	'	'	'	'	'	'	-109	-3	-8
Limited Partners’ interest in net income	$48	$35	$53	$166	$86	$69	$66	$88	$302	$309	$192
Basic and diluted income from continuing operations per limited partner unit	0.17	0.13	0.19	0.73	0.38	0.31	0.3	0.4	1.13	1.39	0.86
Diluted	0.17	0.13	0.19	0.73	0.38	0.31	0.3	0.4	1.13	1.38	0.86

Supplemental_Financial_Stateme2

Supplemental Financial Statement Information (Schedule Of Balance Sheets) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2008	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
In Millions, unless otherwise specified					Parent Company [Member]	Parent Company [Member]	Parent Company [Member]	Parent Company [Member]
Cash and cash equivalents	$372	$126	$86	$68	$9	$18	$27	$0
Accounts receivable from related companies	71	100	'	'	11	1	'	'
Note receivable from affiliate	'	'	'	'	3	0	'	'
Other current assets	311	184	'	'	0	1	'	'
Total current assets	5,597	1,455	'	'	23	20	'	'
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,737	1,497	1	'	6,094	2,226	'	'
INTANGIBLE ASSETS, net	2,291	1,072	'	'	19	0	'	'
GOODWILL	6,434	2,039	1,601	'	9	0	'	'
NON-CURRENT RISK MANAGEMENT ASSETS	43	26	'	'	'	'	'	'
INTANGIBLE ASSETS, net	'	'	'	'	222	50	'	'
Total assets	48,904	20,897	17,678	'	6,367	2,296	'	'
Accounts payable	3,107	512	'	'	1	0	'	'
Accounts payable to related companies	15	33	'	'	15	12	'	'
Interest payable	334	204	'	'	48	35	'	'
Price risk management liabilities	115	90	'	'	5	0	'	'
Accrued and other current liabilities	1,754	764	'	'	1	1	'	'
Current maturities of long-term debt	613	424	'	'	4	0	'	'
Total current liabilities	5,845	1,841	'	'	74	48	'	'
LONG-TERM DEBT, less current maturities	21,440	10,947	'	'	3,840	1,872	'	'
Temporary Equity, Carrying Amount, Attributable to Parent	'	'	'	'	331	323	'	'
OTHER NON-CURRENT LIABILITIES	995	29	'	'	9	0	'	'
COMMITMENTS AND CONTINGENCIES	'	'	'	'	'	'	'	'
General Partner	0	0	'	'	0	0	'	'
Limited Partners – Common Unitholders (279,955,608 and 222,972,708 units authorized, issued and outstanding at December 31, 2012 and 2011, respectively)	2,125	52	'	'	2,125	52	'	'
Accumulated other comprehensive income (loss)	-12	1	'	'	-12	1	'	'
Total partners’ capital	2,113	53	'	'	2,113	53	'	'
Total liabilities and equity	$48,904	$20,897	'	'	$6,367	$2,296	'	'

Supplemental_Financial_Stateme3

Supplemental Financial Statement Information (Schedule Of Statements Of Operations) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	'	'	'	'	'	'	'	'	($580)	($292)	($233)
Interest expense, net of interest capitalized	'	'	'	'	'	'	'	'	-1,018	-740	-625
Bridge loan related fees	'	'	'	'	'	'	'	'	'	'	0
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	212	117	65
Losses on non-hedged interest rate derivatives	'	'	'	'	'	'	'	'	-19	-78	-52
Other, net	'	'	'	'	'	'	'	'	30	17	-4
Income tax benefit	'	'	'	'	'	'	'	'	54	17	14
NET INCOME ATTRIBUTABLE TO PARTNERS	'	'	'	'	'	'	'	'	304	310	193
GENERAL PARTNER’S INTEREST IN NET INCOME	'	'	'	'	'	'	'	'	2	1	1
LIMITED PARTNERS’ INTEREST IN NET INCOME	48	35	53	166	86	69	66	88	302	309	192
Parent Company [Member]	'	'	'	'	'	'	'	'	'	'	'
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	'	'	'	'	'	'	'	'	-53	-30	-22
Interest expense, net of interest capitalized	'	'	'	'	'	'	'	'	-235	-164	-168
Bridge loan related fees	'	'	'	'	'	'	'	'	-62	0	'
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	666	509	456
Losses on non-hedged interest rate derivatives	'	'	'	'	'	'	'	'	-15	0	-53
Other, net	'	'	'	'	'	'	'	'	-4	-5	-20
INCOME BEFORE INCOME TAXES	'	'	'	'	'	'	'	'	297	310	193
Income tax benefit	'	'	'	'	'	'	'	'	-7	0	0
NET INCOME ATTRIBUTABLE TO PARTNERS	'	'	'	'	'	'	'	'	304	310	193
GENERAL PARTNER’S INTEREST IN NET INCOME	'	'	'	'	'	'	'	'	2	1	1
LIMITED PARTNERS’ INTEREST IN NET INCOME	'	'	'	'	'	'	'	'	$302	$309	$192

Supplemental_Financial_Stateme4

Supplemental Financial Statement Information (Schedule Of Statements Of Cash Flows) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$1,078	$1,378	$1,088
Cash paid for acquisitions	-10	-1,972	-345
Net cash used in investing activities	-4,196	-3,874	-1,830
Proceeds from borrowings	12,870	8,262	4,389
Repayments of long-term debt	-8,848	-6,264	-4,078
Distributions to partners	-666	-526	-483
Debt issuance costs	-112	-53	-49
Net cash provided by financing activities	3,364	2,536	760
INCREASE IN CASH AND CASH EQUIVALENTS	246	40	18
CASH AND CASH EQUIVALENTS, beginning of period	126	86	'
CASH AND CASH EQUIVALENTS, end of period	372	126	86
Parent Company [Member]	'	'	'
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	555	469	317
Cash paid for acquisitions	-1,113	0	0
Contributions to affiliates	-487	0	0
Note receivable from affiliate	-221	0	0
Payments received on note receivable from affiliate	55	0	0
MEP Transaction	0	0	3
Net cash used in investing activities	-1,766	0	3
Proceeds from borrowings	2,108	92	1,858
Repayments of long-term debt	-162	-20	-1,632
Distributions to partners	-666	-526	-483
Debt issuance costs	-78	-24	-36
Net cash provided by financing activities	1,202	-478	-293
INCREASE IN CASH AND CASH EQUIVALENTS	-9	-9	27
CASH AND CASH EQUIVALENTS, beginning of period	18	27	0
CASH AND CASH EQUIVALENTS, end of period	$9	$18	$27