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Document And Entity Information - USD ($) $ in Billions	12 Months Ended
Document And Entity Information - USD ($) $ in Billions	Dec. 31, 2011	Feb. 15, 2012	Jun. 30, 2011
Entity Information
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	0001276187
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		222,973,448
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 5.6

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
ASSETS
Cash and cash equivalents	$ 126,342	$ 86,264
Marketable securities	1,229	2,032
Accounts receivable, net of allowance for doubtful accounts of $8,841 and $6,706 as of December 31, 2011 and 2010, respectively	680,491	612,357
Accounts receivable from related companies	100,406	76,331
Inventories	327,963	366,384
Exchanges receivable	21,307	21,926
Price risk management assets	15,802	16,357
Other current assets	181,904	109,359
Total current assets	1,455,444	1,291,010
PROPERTY, PLANT AND EQUIPMENT	16,529,339	13,284,430
ACCUMULATED DEPRECIATION	(1,970,777)	(1,431,698)
PROPERTY, PLANT AND EQUIPMENT, net	14,558,562	11,852,732
ADVANCES TO AND INVESTMENTS IN AFFILIATES	1,496,600	1,359,979
LONG-TERM PRICE RISK MANAGEMENT ASSETS	26,011	13,971
GOODWILL	2,038,975	1,600,611
INTANGIBLE ASSETS, net	1,072,291	1,034,846
OTHER NON-CURRENT ASSETS, net	248,910	225,581
Total assets	20,896,793	17,378,730
LIABILITIES AND EQUITY
Accounts payable	512,023	421,556
Accounts payable to related companies	33,208	27,351
Exchanges payable	17,957	16,003
Price risk management liabilities	90,053	13,172
Accrued and other current liabilities	763,912	567,688
Current maturities of long-term debt	424,160	35,305
Total current liabilities	1,841,313	1,081,075
LONG-TERM DEBT, less current maturities	10,946,864	9,346,067
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES	81,415	79,465
SERIES A CONVERTIBLE PREFERRED UNITS (Note 7)	322,910	317,600
OTHER NON-CURRENT LIABILITIES	244,202	235,848
COMMITMENTS AND CONTINGENCIES (Note 10)
PREFERRED UNITS OF SUBSIDIARY (Note 7)	71,144	70,943
Partners' Capital
General Partner	321	520
Limited Partners:
Common Unitholders (222,972,708 and 222,941,172 units authorized, issued and outstanding as of December 31, 2011 and 2010, respectively)	52,485	115,350
Accumulated other comprehensive income	678	4,798
Total partners' capital	53,484	120,668
Noncontrolling interest	7,335,461	6,127,064
Total equity	7,388,945	6,247,732
Total liabilities and equity	$ 20,896,793	$ 17,378,730

Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 8,841	$ 6,706
Units of Partnership Interest, Amount	222,973	222,941

Consolidated Statements Of Operations $ in Thousands	12 Months Ended
Consolidated Statements Of Operations $ in Thousands	Dec. 31, 2011 USD ($) $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares shares
REVENUES:
Natural gas sales	$ 2,985,471	$ 2,732,153	$ 2,417,741
NGL sales	1,735,242	836,610	472,874
Gathering, transportation and other fees	1,845,267	1,388,034	1,187,969
Retail propane sales	1,360,653	1,314,973	1,190,524
Other	314,070	326,362	148,187
Total revenues	8,240,703	6,598,132	5,417,295
COSTS AND EXPENSES:
Cost of Goods Sold	5,182,999	4,111,337	3,122,056
Operating expenses	918,918	784,546	680,893
Depreciation and amortization	611,809	431,199	325,024
Selling, general and administrative	292,158	234,321	178,924
Total costs and expenses	7,005,884	5,561,403	4,306,897
OPERATING INCOME	1,234,819	1,036,729	1,110,398
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(739,811)	(624,887)	(468,420)
Equity in earnings of affiliates	117,188	65,220	20,597
Losses on disposal of assets	816	5,255	1,564
Gains (losses) on non-hedged interest rate derivatives	(77,806)	(52,357)	33,619
Allowance for equity funds used during construction	957	28,942	10,557
Impairment of investments in affiliates	(5,355)	(52,620)	0
Other, net	15,954	(44,210)	1,913
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	545,130	351,562	707,100
Income tax expense	16,883	13,738	9,229
INCOME FROM CONTINUING OPERATIONS	528,247	337,824	697,871
Loss from discontinued operations	0	(1,244)	0
NET INCOME	528,247	336,580	697,871
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	218,436	143,822	255,398
NET INCOME ATTRIBUTABLE TO PARTNERS	309,811	192,758	442,473
GENERAL PARTNER'S INTEREST IN NET INCOME	959	597	1,370
LIMITED PARTNERS' INTEREST IN NET INCOME	$ 308,852	$ 192,161	$ 441,103
BASIC NET INCOME PER LIMITED PARTNER UNIT \| $ / shares	1.39	0.86	1.98
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING \| shares	222,968,261	222,941,156	222,898,203
DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT \| $ / shares	1.38	0.86	1.98
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING \| shares	222,968,261	222,941,156	222,898,203

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Statement of Income and Comprehensive Income [Abstract]
Net income	$ 528,247	$ 336,580	$ 697,871
Other comprehensive income, net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	(18,952)	49,353	16,958
Change in value of derivative instruments accounted for as cash flow hedges	6,502	19,012	(11,017)
Change in value of available-for-sale securities	(804)	(4,023)	10,924
Other comprehensive income (loss), net of tax, total	(13,254)	64,342	16,865
Comprehensive income	514,993	400,922	714,736
Less: Comprehensive income attributable to noncontrolling interest	209,302	149,738	258,066
Comprehensive income attributable to partners	$ 305,691	$ 251,184	$ 456,670

Consolidated Statement Of Equity - USD ($) $ in Thousands	Total	General Partner [Member]	Common Unitholders [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2008	$ 2,339,316	$ 155	$ (15,762)	$ (67,825)	$ 2,422,748
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(470,658)	(1,457)	(469,201)	0	0
Distributions to noncontrolling interest	381,471	0	0	0	381,471
Subsidiary units issued for cash	999,676	300	96,696	0	902,680
Non-cash compensation expense, net of units tendered by employees for tax withholdings	22,414	0	576	0	21,838
Other, net	(3,762)	0	0	0	(3,762)
Other comprehensive loss, net of tax	16,865	0	0	14,197	2,668
Net income	697,871	1,370	441,103	0	255,398
Balance at Dec. 31, 2009	3,220,251	368	53,412	(53,628)	3,220,099
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Regency Transactions (See Notes 1 and 3)	2,104,981	648	209,065	0	1,895,268
Distributions to partners	(483,048)	(1,495)	(481,553)	0	0
Distributions to noncontrolling interest	567,593	0	0	0	567,593
Subsidiary units issued for cash	1,551,810	441	142,154	0	1,409,215
Non-cash compensation expense, net of units tendered by employees for tax withholdings	25,931	0	936	0	24,995
Other, net	(5,522)	(39)	(825)	0	(4,658)
Other comprehensive loss, net of tax	64,342	0	0	58,426	5,916
Net income	336,580	597	192,161	0	143,822
Balance at Dec. 31, 2010	6,247,732	520	115,350	4,798	6,127,064
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(525,596)	(1,626)	(523,970)	0	0
Distributions to noncontrolling interest	778,557	0	0	0	778,557
Subsidiary units issued for cash	1,902,642	474	152,565	0	1,749,603
Non-cash compensation expense, net of units tendered by employees for tax withholdings	33,990	0	1,139	0	32,851
Subsidiary units issued in acquisition	3,000	0	0	0	3,000
Other, net	(9,259)	(6)	(1,451)	0	(7,802)
Other comprehensive loss, net of tax	(13,254)	0	0	(4,120)	(9,134)
Net income	528,247	959	308,852	0	218,436
Balance at Dec. 31, 2011	$ 7,388,945	$ 321	$ 52,485	$ 678	$ 7,335,461

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 528,247	$ 336,580	$ 697,871
Reconciliation of net income to net cash provided by operating activities:
Impairment of investments in affiliates	5,355	52,620	0
Payment for termination of Parent Company interest rate derivatives (See Note 11)	0	(168,550)	0
Proceeds from termination of ETP interest rate derivatives	0	26,495	0
Depreciation and amortization	611,809	431,199	325,024
Amortization of finance costs charged to interest	19,779	18,111	14,954
Non-cash compensation expense	42,181	31,168	25,833
Losses on disposal of assets	816	5,255	1,564
Distribution in excess of earnings of affiliates, net	3,075	79,975	3,224
Other non-cash	7,281	14,483	3,627
Changes in operating assets and liabilities, net of effects of acquisitions (Note 2)	158,148	259,543	(348,636)
Net cash provided by operating activities	1,376,691	1,086,879	723,461
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(1,971,581)	(345,237)	30,367
Capital expenditures (excluding allowance for equity funds used during construction)	(1,810,230)	(1,509,977)	(748,621)
Contributions in aid of construction costs	25,371	13,720	6,453
Advances to affiliates, net	(149,717)	(92,603)	(655,500)
Proceeds from the sale of assets	33,275	104,118	21,545
Net cash used in investing activities	(3,872,882)	(1,829,979)	(1,345,756)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	8,261,905	4,388,531	3,542,612
Principal payments on debt	(6,263,802)	(4,078,171)	(3,020,587)
Subsidiary equity offering, net of issue costs	1,902,642	1,551,810	936,337
Distributions to partners	(525,596)	(483,048)	(470,658)
Distributions to noncontrolling interests	(778,557)	(567,593)	(381,471)
Debt issuance costs	(53,298)	(48,613)	(7,646)
Other, net	(7,025)	(1,867)	0
Net cash provided by financing activities	2,536,269	761,049	598,587
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	40,078	17,949	(23,708)
CASH AND CASH EQUIVALENTS, beginning of period	86,264	68,315	92,023
CASH AND CASH EQUIVALENTS, end of period	$ 126,342	$ 86,264	$ 68,315

Operations And Organization

12 Months Ended

Dec. 31, 2011

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, 2011, 2010 and 2009, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“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.

At December 31, 2011, our equity interests consisted of:



	General Partner Interest (as a % of total partnership interest)		Incentive Distribution Rights (“IDRs”)		Limited Partner Units
ETP	1.5	%	100	%	50,226,967
Regency	1.8	%	100	%	26,266,791

The consolidated financial statements of ETE presented herein include the results of operations of:

•the Parent Company;


•	our controlled subsidiaries, Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”) (see description of their respective operations below under “Business Operations”);


•	ETP’s and Regency’s wholly-owned subsidiaries; and


•	our wholly-owned subsidiaries that own the general partner and IDR interest in ETP and Regency.

We obtained control of Regency on May 26, 2010 as a result of the “Regency Transactions” (see Note 3), and as such, the year ended December 31, 2010 includes the results of operations of Regency for the period from the acquisition date through the end of the period.

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 2011 presentation. These reclassifications had no impact on net income or total equity.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, Energy Transfer Partners GP, L.P. (“ETP GP”), the General Partner of ETP, ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency, Regency GP LP (“Regency GP”), the General Partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”). 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 are distributions related to its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements, distributions to its partners and holders of the Series A Convertible Preferred Units (the “Preferred Units”) and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to fully understand the financial condition of the Parent Company on a stand-alone basis, see Note 16 for stand-alone financial information apart from that of the consolidated partnership information included herein.

The following is a brief description of ETP’s and Regency’s operations:

•

ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Arkansas, Colorado, Louisiana, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and storage facilities located in Texas. ETP also holds a 70% membership interest in Lone Star NGL LLC (“Lone Star”), a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas, Louisiana and Mississippi.

•

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 Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Bone Spring and Avalon shales, as well as the Permian Delaware basin. Its assets are primarily 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% membership interest in Lone Star.

- Definition

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

+ References

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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Estimates, Significant Accounting Policies and Balance Sheet Detail

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Estimates, Significant Accounting Policies and Balance Sheet Detail

ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

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 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.

Investment in ETP

Revenues for ETP’s sales of natural gas, NGLs including propane, and propane appliances, parts, and fittings 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. Tank rent is recognized ratably over the period it is earned.

ETP’s intrastate transportation and storage and interstate transportation operations’ results are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, ETP’s 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.

ETP’s 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, ETP purchases natural gas from the market, including purchases from ETP’s midstream marketing operations, and from producers at the wellhead.

In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in its storage facilities. ETP also engages in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover its carrying costs and provide for a gross profit margin. ETP expects 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, ETP 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 it operates, competitive factors in the energy industry, and other issues.

Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through its pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and gross margins principally under fee-based or other arrangements in which it receives 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 ETP’s systems and is not directly dependent on commodity prices.

ETP also utilizes other types of arrangements in its 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 ETP 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, and (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s 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.

ETP conducts marketing activities in which it markets the natural gas that flows through its assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells 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.

ETP’s retail propane operations sell propane and propane-related products and services. The Heritage Operating, L.P. (“HOLP”) and Titan Energy Partners, L.P. (“Titan”) customer base includes residential, commercial, industrial and agricultural customers.

In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.

Investment in Regency

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

Certain of our subsidiaries are subject to regulation by certain state and federal authorities and have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us 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 all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheets for the period in which the discontinuance of regulatory accounting treatment occurs.

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.

As a result of ETP’s acquisition of a natural gas compression equipment business in exchange for ETP Common Units, cash acquired in connection with acquisitions during 2009 exceeded the cash we paid during the period.

The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities was comprised as follows:



	Years Ended December 31,
	2011			2010			2009
Accounts receivable	$	6,073		$	92,085		$	28,431
Accounts receivable from related companies	(23,816		)	(26,265		)	(26,321		)
Inventories	50,991			14,750			(101,592		)
Exchanges receivable	620			1,064			22,074
Other current assets	(51,398		)	33,233			8,195
Other non-current assets	7,077			5,843			(1,467		)
Accounts payable	21,452			(66,936		)	(16,024		)
Accounts payable to related companies	5,857			(9,939		)	4,184
Exchanges payable	1,954			(3,841		)	(35,433		)
Accrued and other current liabilities	84,704			72,669			(101,927		)
Other non-current liabilities	(118		)	442			1,401
Price risk management assets and liabilities, net	54,752			146,438			(130,157		)
Net change in operating assets and liabilities, net of effects of acquisitions	$	158,148		$	259,543		$	(348,636	)

Non-cash investing and financing activities and supplemental cash flow information were as follows:



	Years Ended December 31,
	2011		2010		2009
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	225,827	$	108,076	$	46,134
Gain from subsidiary common unit transactions	$	153,039	$	352,307	$	96,996
NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued from acquisitions	$	4,166	$	1,242,604	$	26,237
Subsidiary issuance of Common Units in connection with certain acquisitions	$	3,000	$	584,436	$	63,339
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	728,112	$	547,286	$	440,492
Cash paid for income taxes	$	26,603	$	9,188	$	15,447

Marketable Securities

Marketable securities are classified as available-for-sale securities and are reflected as current assets on the consolidated balance sheets at fair value.

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 valued at the lower of cost or market utilizing the weighted-average cost method. Propane inventories are also valued at the lower of cost or market utilizing the weighted-average cost of propane delivered to the customer service locations, including storage fees and inbound freight costs. The cost of appliances, parts and fittings is determined by the first-in, first-out method.

Inventories consisted of the following:



	December 31,
	2011		2010
Natural gas and NGLs, excluding propane	$	146,132	$	170,179
Propane	86,958		76,341
Appliances, parts and fittings and other	94,873		119,864
Total inventories	$	327,963	$	366,384

ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

During 2009, ETP recorded lower of cost or market adjustments of $54.0 million and fair value adjustments related to its application of fair value hedging of $66.1 million. No lower of cost or market adjustments were recorded in 2011 or 2010.

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,
	2011		2010
Deposits paid to vendors	$	66,231	$	52,192
Prepaid and other	115,673		57,167
Total other current assets	$	181,904	$	109,359

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 Federal Energy Regulatory Commission (“FERC”) mandated lives of the assets. 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. No impairment of long-lived assets was required during the periods presented.

Capitalized interest is included for pipeline construction projects, except for interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of ETP’s revolving credit facility 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,
	2011			2010
Land and improvements	$	137,352		$	103,325
Buildings and improvements (10 to 83 years)	278,829			383,274
Pipelines and equipment (10 to 83 years)	11,358,550			9,709,568
Natural gas and NGL storage facilities (40 years) ⁽¹⁾	789,612			100,909
Bulk storage, equipment and facilities (5 to 83 years)	976,882			736,520
Tanks and other equipment (10 to 30 years)	643,527			623,126
Vehicles (3 to 33 years)	230,609			200,702
Right of way (20 to 83 years)	793,232			637,930
Furniture and fixtures (3 to 33 years)	48,466			41,205
Linepack	58,982			55,744
Pad gas	57,907			57,907
Other (5 to 33 years)	234,440			189,103
Construction work-in-process	920,951			445,117
	16,529,339			13,284,430
Less - Accumulated depreciation	(1,970,777		)	(1,431,698		)
Property, plant and equipment, net	$	14,558,562		$	11,852,732

⁽¹⁾ Includes $682.4 million of natural gas liquids storage facilities acquired in connection with the LDH Acquisition described in Note 3.

We recognized the following amounts of depreciation expense and capitalized interest expense for the periods presented:



	Years Ended December 31,
	2011		2010		2009
Depreciation expense	$	556,569	$	394,698	$	304,129
Capitalized interest, excluding AFUDC	$	12,630	$	4,071	$	11,791

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

In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”), which simplified how entities test goodwill for impairment. ASU 2011-08 gives entities the option, under certain circumstances, to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. ASU 2011-08 was effective for fiscal years beginning after December 15, 2011, and early adoption was permitted. We adopted and applied this standard to our annual impairment tests performed for certain reporting units during the year ended December 31, 2011. There was no material impact to our financial position or results of operations as a result of the adoption of this standard.

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 December 31 for reporting units within ETP's interstate transportation and NGL transportation and services operations and for all of Regency's reporting units. Our annual impairment test is performed as of August 31 for all other 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:



	Investment in ETP			Investment in Regency		Corporate and Other		Total
Balance, December 31, 2009	$	745,505		$	—	$	29,589	$	775,094
Goodwill acquired	36,460			789,789		—		826,249
Other	(732		)	—		—		(732		)
Balance, December 31, 2010	781,233			789,789		29,589		1,600,611
Goodwill acquired	438,364			—		—		438,364
Balance, December 31, 2011	$	1,219,597		$	789,789	$	29,589	$	2,038,975

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 $825.5 million was recorded during the year ended December 31, 2010, primarily due to $789.8 million from the Regency Transactions, in addition to $27.3 million of goodwill ETP recorded from its acquisition of the natural gas gathering company. A net increase in goodwill of $438.4 million was recorded during the year ended December 31, 2011, primarily due to $432.0 million of goodwill recorded by ETP in connection with Lone Star's acquisition of LDH. See further discussion in 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, 2011					December 31, 2010
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	1,058,662	$	(134,909	)	$	971,657	$	(88,583	)
Trade names (20 years)	65,500		(5,185		)	65,500		(1,910		)
Noncompete agreements (3 to 15 years)	15,431		(7,835		)	21,165		(11,888		)
Patents (9 years)	750		(201		)	750		(118		)
Other (10 to 15 years)	1,320		(581		)	1,320		(492		)
Total amortizable intangible assets	1,141,663		(148,711		)	1,060,392		(102,991		)
Non-amortizable intangible assets:
Trademarks	79,339		—			77,445		—
Total intangible assets	$	1,221,002	$	(148,711	)	$	1,137,837	$	(102,991	)

We recorded the following intangible assets in conjunction with the Regency Transactions:



Amortizable intangible assets:
Customer relationships, contracts and agreements (30 years)	$	600,860
Trade names (20 years)	65,500
Total intangible and other assets acquired	$	666,360

During 2011, in connection with the LDH Acquisition, ETP recorded customer contracts of $81.0 million with useful lives ranging from 3 to 15 years. See discussions of amounts recorded in the Regency Transactions and the LDH Acquisition at Note 3.

Aggregate amortization expense of intangibles assets was as follows:



	Years Ended December 31,
	2011		2010		2009
Reported in depreciation and amortization	$	54,655	$	35,602	$	20,895

Estimated aggregate amortization expense of intangible assets for the next five years was as follows:



Years Ending December 31:
2012	$	44,793
2013	40,871
2014	39,746
2015	39,746
2016	39,746

Amortizable intangible assets with a gross carrying amount of approximately $127.7 million as of December 31, 2011 were deconsolidated in January 2012 in connection with the contribution of ETP's propane operations as described in Note 3. Amounts reflected above do not include any future amortization related to these deconsolidated 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. Our annual impairment test is performed as of August 31 for reporting units within ETP and as of December 31 for Regency’s reporting units. No impairment of intangible assets was required during the periods presented in these consolidated financial statements.

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,
	2011		2010
Unamortized financing costs (3 to 30 years)	$	132,375	$	98,067
Regulatory assets	88,993		92,939
Other	27,542		34,575
Total other non-current assets, net	$	248,910	$	225,581

Asset Retirement Obligation

Our subsidiaries have determined that they are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates. However, ETP’s and Regency’s management were not able to reasonably measure the fair value of the asset retirement obligations as of December 31, 2011 or 2010 because the settlement dates were indeterminable. ETP and Regency will record an asset retirement obligation in the periods in which management can reasonably determine the settlement dates.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	December 31,
	2011		2010
Interest payable	$	204,182	$	191,466
Customer advances and deposits	100,525		111,448
Accrued capital expenditures	228,877		87,260
Accrued wages and benefits	80,205		76,592
Taxes payable other than income taxes	79,331		36,204
Income taxes payable	14,781		8,344
Other	56,011		56,374
Total accrued and other current liabilities	$	763,912	$	567,688

Deposits or advances are received from ETP and Regency’s customers as prepayments for natural gas deliveries in the following month and from ETP’s propane customers as security or prepayments for future propane deliveries. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

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.

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 2011 was $12.21 billion and $11.37 billion, respectively. As of December 31, 2010, the aggregate fair value and carrying amount of our consolidated debt obligations was $10.23 billion and $9.38 billion, respectively.

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.

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, 2011 and 2010 based on inputs used to derive their fair values:



	Fair Value Measurements at December 31, 2011 Using
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	1,229		$	1,229		$	—		$	—
Interest rate derivatives	36,301			—			36,301			—
Commodity derivatives:
Condensate — Forward Swaps	538			—			538			—
Natural Gas:
Basis Swaps IFERC/NYMEX	62,924			62,924			—			—
Swing Swaps IFERC	15,002			1,687			13,315			—
Fixed Swaps/Futures	218,479			214,572			3,907			—
Options — Puts	6,435			—			6,435			—
Forward Physical Swaps	699			—			699			—
NGLs:
Forward Swaps	94			—			94			—
Options — Puts	309			—			309			—
Propane — Forward Swaps	9			—			9			—
Total commodity derivatives	304,489			279,183			25,306			—
Total Assets	$	342,019		$	280,412		$	61,607		$	—
Liabilities:
Interest rate derivatives	$	(117,490	)	$	—		$	(117,490	)	$	—
Series A Convertible Preferred Units	(322,910		)	—			—			(322,910		)
Embedded derivatives in the Regency Preferred Units	(39,049		)	—			—			(39,049		)
Commodity derivatives:
Condensate — Forward Swaps	(1,567		)	—			(1,567		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(82,290		)	(82,290		)	—			—
Swing Swaps IFERC	(16,074		)	(3,061		)	(13,013		)	—
Fixed Swaps/Futures	(148,111		)	(148,111		)	—			—
Options — Calls	(12		)	—			(12		)	—
Forward Physical Swaps	(712		)	—			(712		)	—
NGLs — Forward Swaps	(8,561		)	—			(8,561		)	—
Propane — Forward Swaps	(4,131		)	—			(4,131		)	—
Total commodity derivatives	(261,458		)	(233,462		)	(27,996		)	—
Total Liabilities	$	(740,907	)	$	(233,462	)	$	(145,486	)	$	(361,959	)



	Fair Value Measurements at December 31, 2010 Using
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	2,032		$	2,032		$	—		$	—
Interest rate derivatives	20,790			—			20,790			—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	15,756			15,756			—			—
Swing Swaps IFERC	1,682			1,562			120			—
Fixed Swaps/Futures	44,955			42,474			2,481			—
Options — Calls	75			—			75			—
Options — Puts	26,241			—			26,241			—
NGLs — Forward Swaps	192			—			192			—
Propane — Forward Swaps	6,864			—			6,864			—
Total commodity derivatives	95,765			59,792			35,973			—
Total Assets	$	118,587		$	61,824		$	56,763		$	—
Liabilities:
Interest rate derivatives	$	(20,922	)	$	—		$	(20,922	)	$	—
Series A Convertible Preferred Units	(317,600		)	—			—			(317,600		)
Embedded derivatives in the Regency Preferred Units	(57,023		)	—			—			(57,023		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(17,372		)	(17,372		)	—			—
Swing Swaps IFERC	(3,768		)	(3,520		)	(248		)	—
Fixed Swaps/Futures	(42,252		)	(41,825		)	(427		)	—
Options — Calls	(2,643		)	—			(2,643		)	—
Options — Puts	(7		)	—			(7		)	—
NGLs — Forward Swaps	(10,684		)	—			(10,684		)	—
WTI Crude Oil	(3,581		)	—			(3,581		)	—
Total commodity derivatives	(80,307		)	(62,717		)	(17,590		)	—
Total Liabilities	$	(475,852	)	$	(62,717	)	$	(38,512	)	$	(374,623	)

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, 2011. There were no transfers between the fair value hierarchy levels during the years ended December 31, 2011 or 2010.



Net liability balance, December 31, 2010	$	(374,623	)
Net unrealized gains included in other income (expense)	12,664
Net liability balance, December 31, 2011	$	(361,959	)

Prior to the Regency Transactions in 2010, ETP adjusted the investment in MEP to fair value based on the present value of expected future cash flows (Level 3), resulting in a nonrecurring fair value adjustment of $52.6 million. See Note 4.

Shipping and Handling Costs

Shipping and handling costs related to fuel sold are included in cost of products sold. ETP’s shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and totaled $40.4 million, $43.3 million and $55.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. ETP does not separately charge propane shipping and handling costs to customers.

Costs and Expenses

Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, storage fees and inbound freight on propane, 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, shipping and handling costs related to propane, 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.

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 limited partnership. 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 limited partnership, we are generally not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualifying income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the years ended December 31, 2011, 2010 and 2009, our non-qualifying income did not exceed the statutory limit.

Those subsidiaries which are taxable corporations follow the asset and liability method of accounting for income taxes, under which deferred income taxes are recorded based upon differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled.

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level.

The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows:



	Years Ended December 31,
	2011			2010		2009
Current expense (benefit):
Federal	$	(842	)	$	1,602	$	(8,850	)
State	16,883			8,594		9,657
Total	16,041			10,196		807
Deferred expense (benefit):
Federal	416			2,788		8,643
State	426			754		(221		)
Total	842			3,542		8,422
Total income tax expense	$	16,883		$	13,738	$	9,229

As of December 31, 2011 and 2010, we had net deferred income tax liabilities of $217.2 million and $213.9 million, respectively, recorded in other non-current liabilities in our consolidated balance sheets. Substantially all of our deferred tax liability relates to property, plant and equipment, including $146.6 million and $143.9 million as of December 31, 2011 and 2010, respectively, and basis differences associated with ETP’s Class E Units of $72.2 million and $70.2 million as of December 31, 2011 and 2010, respectively. As of December 31, 2011 and 2010, we had deferred income tax liabilities of $0.1 million and $0.4 million, respectively, recorded in accrued and other current liabilities in our consolidated balance sheets.

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 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 Accumulated Other Comprehensive Income (“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 11 for additional information related to interest rate derivatives.

Allocation of Income (Loss)

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 Transactions

12 Months Ended

Dec. 31, 2011

Acquisitions and Dispositions [Abstract]

Acquisitions and Related Transactions

ACQUISITIONS AND RELATED TRANSACTIONS:

Pending Southern Union Acquisition

On July 19, 2011, we entered into a Second Amended and Restated Plan of Merger (the “SUG Merger Agreement”) with Sigma Acquisition Corporation, a Delaware corporation and our wholly-owned subsidiary (“Merger Sub”), and Southern Union Company, a Delaware corporation (“SUG”). The SUG Merger Agreement modifies certain terms of the Amended and Restated Agreement and Plan of Merger entered into by us, Merger Sub and SUG on July 4, 2011 (the "First Amended Merger Agreement"). Under the terms of the SUG Merger Agreement, Merger Sub will merge with and into SUG, with SUG continuing as the surviving entity and becoming our wholly-owned subsidiary (the “SUG Merger”) subject to certain conditions to close. Pursuant to the SUG Merger Agreement, ETE will acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion at the time of the execution of the SUG Merger Agreement, including $5.7 billion in cash and ETE Common Units and $3.7 billion of existing SUG indebtedness. Stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.

Consummation of the SUG Merger is subject to customary conditions, including, without limitation: (i) the adoption of the SUG Merger Agreement by the stockholders of SUG, (ii) the receipt of required approvals from the Federal Energy Regulatory Commission (“FERC”), the Missouri Public Service Commission and, if required, the Massachusetts Department of Public Utilities, (iii) the effectiveness of a registration statement on Form S-4 relating to the ETE Common Units to be issued in the SUG Merger, and (iv) the absence of any law, injunction, judgment or ruling prohibiting or restraining the SUG Merger or making the consummation of the SUG Merger illegal. On July 28, 2011, the waiting period applicable to the SUG Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act") expired. On September 23, 2011, the FERC issued a letter order authorizing the transfer of FERC-jurisdictional facilities resulting from the SUG Merger. On October 27, 2011, the registration statement on Form S-4 was declared effective by the SEC. On December 9, 2011, the special meeting of the SUG stockholders was held and the SUG stockholders voted to approve the SUG Merger. We and SUG have made filings with the Missouri Public Service Commission and expect to receive its approval of the SUG Merger in the first quarter of 2012.

Citrus Transaction

On July 19, 2011, ETP entered into an Amended and Restated Agreement and Plan of Merger with us (the “Citrus Merger Agreement”). The Citrus Merger Agreement modifies certain terms of the Agreement and Plan of Merger entered into by ETP and us on July 4, 2011. Pursuant to the terms of the SUG Merger Agreement, immediately prior to the effective time of the SUG Merger, we will assign and SUG will assume the benefits and obligations of us under the Amended Citrus Merger Agreement. If ETP does not consummate the Citrus Acquisition on or before April 17, 2012, or the Citrus Merger Agreement is terminated at any time on or before such time, ETP must redeem the notes at a redemption price equal to 101% of the aggregate principal amount of the notes, plus accrued and unpaid interest, if any, to, but excluding, the redemption date.

Under the Amended Citrus Merger Agreement, it is anticipated that SUG will cause the contribution to ETP of a 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission pipeline system and is currently jointly owned by SUG and El Paso Corporation (“El Paso”) (the “Citrus Acquisition”). The Citrus Acquisition will be effected through the merger of Citrus ETP Acquisition, L.L.C., a Delaware limited liability company and wholly-owned subsidiary of ETP, with and into CrossCountry Energy, LLC, a Delaware limited liability company and wholly-owned subsidiary of SUG that indirectly owns a 50% interest in Citrus Corp. (“CrossCountry”). In exchange for the interest in Citrus Corp., SUG will receive approximately $2.0 billion, consisting of approximately $1.895 billion in cash and $105 million of ETP Common Units, with the value of the ETP Common Units based on the volume-weighted average trading price for the 10 consecutive trading days ending immediately prior to the date that is three trading days prior to the closing date of the Citrus Acquisition. In order to increase the expected accretion to be derived from the Citrus Acquisition, we have agreed to relinquish our rights to approximately $220 million of incentive distributions from ETP that we would otherwise be entitled to receive over 16 consecutive quarters following the closing of the transaction.

The Citrus Merger Agreement includes customer representations, warranties and covenants of ETP and us (including representations, warranties and covenants relating to SUG, CrossCountry and certain of CrossCountry’s affiliates). Consummation of the Citrus Acquisition is subject to customary conditions, including, without limitation: (i) satisfaction or waiver of the closing conditions set forth in the SUG Merger Agreement, (ii) the receipt by ETP of any necessary waivers or amendments to its credit agreement, (iii) the amendment of ETP’s partnership agreement to reflect the agreed upon relinquishment by us of incentive distributions from ETP discussed above, and (iv) the absence of any order, decree, injunction or law prohibiting or making the consummation of the transactions contemplated by the Citrus Merger Agreement illegal. The Citrus Merger Agreement contains certain termination rights for both us and ETP, including among others, the right to terminate if the Citrus Acquisition is not completed by December 31, 2012 or if the Merger SUG Agreement is terminated.

Pursuant to the Amended Citrus Merger Agreement, we have granted ETP a right of first offer with respect to any disposition by us or SUG of Southern Union Gas Services, a subsidiary of SUG that owns and operates a natural gas gathering and processing system serving the Permian Basin in West Texas and New Mexico.

On November 17, 2011, CrossCountry filed a petition in the Court of Chancery in the State of Delaware seeking a declaratory judgment against El Paso that El Paso’s right of first refusal under a Capital Stock Agreement (“CSA”) governing the Citrus Corp. joint venture between CrossCountry and El Paso would not be triggered by the Citrus Acquisition. This petition was filed by CrossCountry following an exchange of letters between El Paso and SUG in which El Paso stated that it believed the Citrus Acquisition violated the provisions of the CSA related to transfers of equity interests with respect to Citrus Corp. On December 27, 2011, El Paso filed its answer to CrossCountry’s petition and, in addition, El Paso brought third-party claims against ETP, ETE and SUG. El Paso’s third-party complaint against ETE and ETP seek declaratory relief regarding El Paso’s rights under the CSA. Specifically, El Paso claims that the Citrus Acquisition violates its right of first refusal and seeks rescission of the Citrus Acquisition or, alternatively, damages. The parties are currently engaged in discovery and the case is scheduled to go to trial on April 26, 2012. ETE and ETP believe that El Paso’s assertions related to the Citrus Acquisition under the CSA are without merit.

SUG Merger Financing

We intend to finance a portion of the cash component of the SUG Merger consideration with debt financing. In connection with entering into the merger agreement, we entered into a senior bridge term loan credit agreement (the "Bridge Loan Agreement") with the Bridge Lenders, pursuant to which, subject to the conditions set forth therein, the Bridge Lenders have agreed to provide a 364-day Bridge Term Loan Facility in an aggregate principal amount of $3.7 billion. Our ability to borrow under the Bridge Loan Agreement is subject to the satisfaction of certain conditions precedent, including the absence of a material adverse affect on SUG having occurred subsequent to December 31, 2010 and the delivery of certain documents requested by the administrative agent (such as financial statements, favorable opinions of counsel and customary corporate authorization documents) and the payment of relevant fees and expenses. We may use the proceeds of the loans under the Bridge Loan Agreement to finance the SUG Merger, to repay its remaining indebtedness under the Parent Company Credit Agreement (to the extent repaid on the date of initial borrowing under the Bridge Loan Agreement) and to pay transaction costs related to the consummation of the SUG Merger and the Bridge Loan Agreement.

In February 2012, we launched the syndication of a new senior secured credit facility of up to $2.3 billion. We intend to use the net proceeds from the senior secured credit facility, along with proceeds received from ETP in the Citrus Acquisition, to fund the cash portion of the SUG Merger and pay related fees and expenses, including existing borrowings under ETE's revolving credit facility and for general partnership purposes. Upon closing, the new senior secured credit facility, combined with proceeds from the Citrus Acquisition, is expected to replace the previously announced $3.7 billion Bridge Term Facility.

2012 Transaction

Propane Operations

On January 12, 2012, ETP contributed its propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”), to AmeriGas Partners, L.P. (“AmeriGas”). ETP received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. AmeriGas assumed approximately $71.0 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. Under a unitholder agreement with AmeriGas, ETP is obligated to hold the approximately 29.6 million AmeriGas common units that it received in this transaction until January 2013.

We have not reflected the Propane operations as discontinued operations as ETP will have a continuing involvement in this business as a result of the investment in AmeriGas that was transferred to ETP as consideration for the transaction.

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 $592.7 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 ETP reporting segment, while Lone Star’s results are recorded as an equity method investment in our 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.

The following table summarizes the assets acquired and liabilities assumed recognized as of the acquisition date:



Total current assets	$	118,177
Property, plant and equipment⁽¹⁾	1,419,591
Goodwill	432,026
Intangible assets	81,000
Other assets	157
	2,050,951

Total current liabilities	74,964
Other long-term liabilities	438
	75,402
Total consideration	1,975,549
Cash received	31,231
Total consideration, net of cash received	$	1,944,318


⁽¹⁾	Property, plant and equipment (and estimated useful lives) acquired in the LDH Acquisition consisted of the following:



Land and improvements	$	30,759
Buildings and improvements (10 to 40 years)	3,123
Pipelines and equipment (20 to 65 years)	662,881
Natural gas liquids storage (40 years)	682,419
Linepack	704
Vehicles (3 to 20 years)	242
Furniture and fixtures (3 to 10 years)	49
Other (5 to 10 years)	8,526
Construction work-in-process	30,888
Property, plant and equipment	$	1,419,591

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the years ended December 31, 2011 and 2010 are presented as if the acquisitions of LDH and Regency had been completed on January 1, 2010:



	Years Ended December 31,
	2011		2010
Revenues	$	8,349,292	$	7,406,943
Net income	520,034		347,572
Net income attributable to partners	307,809		228,206
Basic net income per Limited Partner unit	$	1.38	$	1.02
Diluted net income per Limited Partner unit	$	1.38	$	1.02

The pro forma consolidated results of operations include adjustments to:


•	include the results of LDH and Regency for all periods presented;


•	include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting;


•	include incremental interest expense related to financing the purchase price;


•	adjust for one-time expenses; and


•	adjust for relative changes in ownership resulting from both transactions.

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.

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 12.3 million ETP Common Units we previously owned; and


•	acquired 26.3 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.

The following summarizes the assets acquired and liabilities assumed in the Regency Transactions, as well as the fair value of the noncontrolling interest in Regency:



Total current assets	$	189,502
Property, plant and equipment	1,548,384
Advances to and investments in affiliates	739,164
Goodwill	789,789
Intangible assets	666,360
Other assets	37,693
	3,970,892
Total current liabilities	192,788
Long-term debt	1,239,863
Other long-term liabilities	57,517
Regency convertible preferred units	70,793
Noncontrolling interest	2,104,981
	3,665,942
Total consideration	304,950
Cash received	23,995
Total consideration, net of cash received	$	280,955

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 $68.2 million and goodwill of $27.3 million.

In September 2010, Regency completed its acquisition of Zephyr, a Texas based field services company for approximately $193.3 million in cash. In connection with this transaction, Regency recorded intangible assets of $119.4 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 $70.2 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.

2009 Transactions

In November 2009, ETP acquired all of the outstanding equity interests of a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas, in exchange for the issuance of 1,450,076 ETP Common Units having an aggregate market value of approximately $63.3 million on the closing date. In connection with this transaction, ETP received cash of $41.1 million, assumed total liabilities of $30.5 million, which includes $8.4 million in notes payable and recorded goodwill of $8.7 million.

In August 2009, ETP acquired Energy Transfer Group, L.L.C. (“ETG”), as described in Note 13. In connection with this transaction, ETP assumed liabilities of $33.5 million and recorded goodwill of $1.7 million.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 88-16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 51, 52
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Appendix F
-Paragraph F4
-Subparagraph e

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Investments In Affiliates

12 Months Ended

Dec. 31, 2011

Investment In Affiliates [Abstract]

Investments In Affiliates

INVESTMENTS IN AFFILIATES:

Midcontinent Express Pipeline LLC

In conjunction with the Regency Transactions, the Parent Company acquired from ETP a 49.9% interest in MEP, which it immediately contributed to Regency. ETP recorded a non-cash charge of approximately $52.6 million during the year ended December 31, 2010 to reduce the carrying value of its interest in MEP to its estimated fair value. In addition to the 49.9% interest in MEP, the Parent Company also acquired an option to purchase ETP’s remaining 0.1% interest in MEP in May 2011, which the Parent Company also transferred to Regency. In September 2011, Regency exercised its option to acquire the remaining 0.1% interest in MEP from ETP for approximately $1.2 million in cash.

MEP 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 the RIGS Haynesville Partnership Co. joint venture (“HPC”), which, through its ownership of the Regency Intrastate Gas System (“RIGS”), delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450 mile intrastate pipeline system.

Fayetteville Express Pipeline LLC

ETP owns a 50% interest in the Fayetteville Express Pipeline LLC (“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.

Ranch Joint Venture

On December 2, 2011, Ranch Westex JV LLC (“Ranch JV”) was formed by Regency, Anadarko Pecos Midstream LLC and Chesapeake West Texas Processing, L.L.C., each owning 33.33% of the joint venture. Ranch JV, upon completion of construction in 2012, will process natural gas delivered from the NGL-rich Bone Spring and Avalon shale formations in West Texas. The project consists of two plants, a 25 MMcf/d refrigeration plant and a 100 MMcf/d cryogenic processing plant. The initial start-up of the refrigeration unit is expected to be in service by the second quarter of 2012, with full facilities available by the fourth quarter of 2012.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, MEP, HPC and FEP (on a 100% basis for all periods presented).



	December 31,
	2011		2010
Current assets	$	88,583	$	83,735
Property, plant and equipment, net	3,987,460		4,052,396
Other assets	152,904		160,655
Total assets	$	4,228,947	$	4,296,786
Current liabilities	$	83,989	$	91,860
Non-current liabilities	1,478,499		1,772,686
Equity	2,666,459		2,432,240
Total liabilities and equity	$	4,228,947	$	4,296,786



	Years Ended December 31,
	2011		2010		2009
Revenue	$	569,116	$	406,346	$	142,076
Operating income	324,686		221,623		66,333
Net income	242,316		166,910		56,247

Net Income Per Limited Partner Unit

12 Months Ended

Dec. 31, 2011

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 Series A Convertible Preferred Units, because inclusion would have been antidilutive. The Series A Convertible Preferred Units have a liquidation preference of $300.0 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,
	2011			2010			2009
Basic Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	308,852		$	192,161		$	441,103
Weighted average limited partner units	222,968,261			222,941,156			222,898,203
Basic net income per limited partner unit	$	1.39		$	0.86		$	1.98
Diluted Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	308,852		$	192,161		$	441,103
Dilutive effect of Unit Grants	(620		)	(228		)	(410		)
Diluted net income available to limited partners	$	308,232		$	191,933		$	440,693
Weighted average limited partner units	222,968,261			222,941,156			222,898,203
Diluted net income per limited partner unit	$	1.38		$	0.86		$	1.98

Discontinued operations per unit has been omitted as the impact rounds to $0.00 for all periods presented.

Debt Obligations

12 Months Ended

Dec. 31, 2011

Debt Obligations [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

Our debt obligations consist of the following:



	December 31,
	2011			2010
Parent Company Indebtedness:
ETE Senior Notes, due October 15, 2020	$	1,800,000		$	1,800,000
ETE Senior Secured Revolving Credit Facility	71,500			—
Subsidiary Indebtedness:
ETP Senior Notes:
5.65% Senior Notes due August 1, 2012	400,000			400,000
6.0% Senior Notes due July 1, 2013	350,000			350,000
8.5% Senior Notes due April 15, 2014	350,000			350,000
5.95% Senior Notes due February 1, 2015	750,000			750,000
6.125% Senior Notes due February 15, 2017	400,000			400,000
6.7% Senior Notes due July 1, 2018	600,000			600,000
9.7% Senior Notes due March 15, 2019	600,000			600,000
9.0% Senior Notes due April 15, 2019	650,000			650,000
4.65% Senior Notes due June 1, 2021	800,000			—
6.625% Senior Notes due October 15, 2036	400,000			400,000
7.5% Senior Notes due July 1, 2038	550,000			550,000
6.05% Senior Notes due June 1, 2041	700,000			—
Regency Senior Notes:
9.375% Senior Notes due June 1, 2016	250,000			250,000
6.875% Senior Notes due December 1, 2018	600,000			600,000
6.5% Senior Notes due July 15, 2021	500,000			—
Transwestern Senior Unsecured Notes:
5.39% Senior Notes due November 17, 2014	88,000			88,000
5.54% Senior Notes due November 17, 2016	125,000			125,000
5.64% Senior Notes due May 24, 2017	82,000			82,000
5.36% Senior Notes due December 9, 2020	175,000			175,000
5.89% Senior Notes due May 24, 2022	150,000			150,000
5.66% Senior Notes due December 9, 2024	175,000			175,000
6.16% Senior Notes due May 24, 2037	75,000			75,000
HOLP Senior Secured Notes:
Senior Secured Notes with interest rates ranging from 7.26% to 8.87%	71,314			103,127
Revolving Credit Facilities:
ETP Revolving Credit Facility	314,438			402,327
Regency Revolving Credit Facility	332,000			285,000
Other Long-Term Debt	10,434			9,671
Unamortized discounts, net	(10,309		)	(6,013		)
Fair value adjustments related to interest rate swaps	11,647			17,260
	11,371,024			9,381,372
Current maturities	(424,160		)	(35,305		)
	$	10,946,864		$	9,346,067

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude (i) maturities of long-term debt related to ETP's Propane Business, which was contributed to AmeriGas in January 2012 (see Note 3), and (ii) $1.3 million in net unamortized discounts and fair value adjustments related to interest rate swaps:



2012	$	400,043
2013	350,046
2014	770,000
2015	821,500
2016	689,438
Thereafter	8,257,000
Total	$	11,288,027

Long-term debt reflected on our consolidated balance sheet 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. As of December 31, 2011 long-term debt includes $11.6 million of fair value adjustments to interest rate swaps, which will be amortized as a reduction of interest expense until 2015.

Senior Notes

ETE Senior Notes

In September 2010, the Parent Company completed a public offering of $1.8 billion aggregate principal amount of 7.5% Senior Notes due October 15, 2020. We used net proceeds of approximately $1.77 billion to repay all of the outstanding indebtedness under our then existing revolving credit facility and term loan facility, to fund the cost to terminate the interest rate swap agreements related to those borrowings, and for general partnership purposes. We may redeem some or all of the notes at any time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest is payable semi-annually.

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.

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.

The 9.7% ETP Senior Notes contain a put option at par exercisable on March 15, 2012. The current market value of these notes is significantly in excess of the principal amount making a repurchase at par value uneconomic by the holder. However, if such repurchase were to occur, ETP would refinance any amounts paid on a long-term basis.

In May 2011, ETP completed a public offering of $800 million aggregate principal amount of 4.65% Senior Notes due June 1, 2021 and $700 million aggregate principal amount of 6.05% Senior Notes due June 1, 2041. ETP used the proceeds, net of commissions, of $1.48 billion to repay all of the borrowings outstanding under its revolving credit facility (the “ETP Credit Facility”), to fund capital expenditures related to pipeline construction projects and for general partnership purposes. ETP may redeem some or all of the ETP Senior Notes at any time pursuant to the terms of the indenture and related indenture supplements subject to the payment of a “make-whole” premium. Interest is payable semi-annually.

In January 2012, ETP completed a public offering of $1 billion aggregate principal amount of 5.20% Senior Notes due February 1, 2022 and $1 billion aggregate principal amount of 6.50% Senior Notes due February 1, 2042. ETP expects to use the net proceeds of $1.98 billion to fund the cash portion of the purchase price of the Citrus Transaction and for general partnership purposes. ETP may redeem some or all of the notes at any time and from time to time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually. If ETP does not consummate the Citrus Acquisition on or before April 17, 2012, or the Citrus Merger Agreement is terminated on or before such date, ETP must redeem the $2.0 billion of senior notes at a redemption price equal to 101% of the aggregate principal amount of the notes, plus accrued and unpaid interest.

In January 2012, ETP announced a cash tender offer for up to $750 million aggregate principal amount of specified series of the ETP Senior Notes. The tender offer consisted of two separate offers: an Any and All Offer and a Maximum Tender Offer.

In the Any and All Offer, ETP offered to purchase, under certain conditions, any and all of its 5.65% Senior Notes due August 1, 2012, at a fixed price. Pursuant to the Any and All Offer, ETP purchased $292.0 million in aggregate principal amount on January 19, 2012.

In the Maximum Tender Offer, ETP offered to purchase, under certain conditions, certain series of outstanding ETP Senior Notes at a fixed spread over the index rate. Pursuant to this tender offer, on February 7, 2012, ETP purchased $200.0 million aggregate principal amount of its 9.7% Senior Notes due March 15, 2019, $200.0 million aggregate principal amount of its 9.0% Senior Notes due April 15, 2019 and $58.1 million aggregate principal amount of its 8.5% Senior Notes due April 15, 2014.

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.

HOLP Senior Secured Notes

All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the HOLP Senior Secured Notes. Interest is payable quarterly or semiannually and principal payments are made in annual installments through 2020 except for a one time payment of $16.0 million due in 2013. In connection with ETP's contribution of the Propane Business to AmeriGas, this debt was assumed by AmeriGas.

Regency Senior Notes

Regency Senior Notes due 2016. Regency has $250 million of Regency Senior Notes due 2016 that mature on June 1, 2016. The senior notes bear interest at 9.375% with interest payable semi-annually.

At any time before June 1, 2012, up to 35% of the Regency Senior Notes due 2016 can be redeemed with the proceeds of an equity offering at a price of 109.375% plus accrued interest. Beginning June 1, 2013, Regency may redeem all or part of these notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest. At any time prior to June 1, 2013, Regency may also redeem all or part of the Regency Senior Notes due 2016 at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the treasury rate (as defined in the indenture governing the senior notes) as of such redemption date plus 0.50% over the principal amount of the note.

Regency Senior Notes due 2018. In October 2010, Regency completed a public offering of $600.0 million aggregate principal amount of 6.875% senior notes due 2018. Interest will be paid semi-annually in arrears on June 1 and December 1, commencing June 1, 2011. Regency capitalized $12.2 million in debt issuance costs which will amortize over the term of the senior notes. The proceeds were used to redeem Regency’s senior notes due 2013 and to partially repay outstanding borrowings under the Regency Credit Facility.

At any time before December 1, 2013, up to 35% of the Regency Senior Notes due 2018 can be redeemed at a price of 106.875% plus accrued interest. Beginning December 1, 2014, Regency may redeem all or part of the Regency Senior Notes due 2018 for the principal amount plus a declining premium until December 31, 2016, and thereafter at par, plus accrued and unpaid interest. At any time prior to December 1, 2014, Regency may also redeem all or part of the Regency Senior Notes due 2018 at a price equal to 100% of the principal amount redeemed plus accrued interest and the applicable premium, which equals to the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at December 1, 2014 plus (ii) all required interest payments due on the note through December 1, 2014, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 0.50% over the principal amount of the note.

Regency Senior Notes due 2021. In May 2011, Regency issued $500 million aggregate principal amount of 6.50% Senior Notes due July 15, 2021 (the “Regency 2021 Notes”). Regency used the proceeds, net of commissions, of approximately $491.3 million to repay borrowings outstanding under its revolving credit facility (the “Regency Credit Facility”). Regency capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the Regency 2021 Notes. Interest will be paid semi-annually.

At any time prior to July 15, 2016, Regency may redeem some or all of the Regency 2021 Notes at a redemption price equal to 100% of the principal amount plus a “make-whole” premium, plus accrued and unpaid interest to the redemption date. At any time before July 15, 2014, Regency may redeem up to 35% of the aggregate principal amount of the Regency 2021 Notes then outstanding at a redemption price equal to 106.5% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to the redemption date.

Upon a change of control followed by a rating decline within 90 days, each noteholder of Regency’s senior notes will be entitled to require Regency to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. Subsequent to the Regency Transactions, no noteholder has exercised this option.

Revolving Credit Facilities

ETE Senior Secured Credit Facility

Concurrent with the closing of its senior notes offering in September 2010, the Parent Company terminated its $500 million senior secured revolving credit facility and entered into a $200 million five-year senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015.

In February 2012, ETE launched the syndication of a new senior secured credit facility of up to $2.3 billion. ETE intends to use the net proceeds from the senior secured credit facility, along with proceeds received from ETP in the Citrus Acquisition, to fund the cash portion of the SUG Merger and pay related fees and expenses, including existing borrowings under ETE's revolving credit facility and for general partnership purposes. We have also secured $3.7 billion in committed financing from the Bridge Loan Lenders to fund a portion of the cash consideration related to the SUG Merger. See additional discussion of the SUG Merger at Note 3.

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, 2011, we had a balance of $71.5 million outstanding under the Parent Company Credit Agreement and the amount available for future borrowings was $128.5 million. The weighted average interest rate on the total amount outstanding as of December 31, 2011 was 3.46%.

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%.

As of December 31, 2011, ETP had a balance of $314.4 million outstanding under the ETP Credit Facility and, taking into account letters of credit of approximately $25.6 million, $2.16 billion available for future borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2011 was 1.78%.

Regency Credit Facility

The Regency Credit Facility has aggregate revolving commitments of $900 million, with $200 million of availability for letters of credit. Regency also has the option to request an additional $250 million in revolving commitments with ten business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the credit facility have been met. The maturity date of the Regency Credit Facility is June 15, 2014.

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.

As of December 31, 2011, Regency had a balance of $332.0 million outstanding under the Regency Credit Facility in revolving credit loans and approximately $19.0 million in letters of credit. The total amount available under the Regency Credit Facility, as of December 31, 2011, which is reduced by any letters of credit, was approximately $549.0 million. The weighted average interest rate on the total amount outstanding as of December 31, 2011 was 3.18%.

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 not exceed 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 Regency Gas Services ("RGS," a wholly-owned subsidiary of Regency) 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.

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, ETP and Regency 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, 2011.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Redeemable Preferred Units

12 Months Ended

Dec. 31, 2011

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, 2011 and 2010. 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 2011, we recorded non-cash charges of approximately $5.3 million to increase the carrying value of the Preferred Units to the estimated fair value of $322.9 million as of December 31, 2011. During 2010, we recorded non-cash charges of approximately $12.7 million to increase the carrying value of the Preferred Units to the estimated fair value of $317.6 million as of December 31, 2010.

Preferred Units of Subsidiary

Regency had 4,371,586 Regency Preferred Units outstanding at December 31, 2011, which were convertible into 4,632,389 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 Preferred Units	Amount
Balance at date of Acquisition	4,371,586	$	70,793
Accretion to redemption value	—	150
Balance, December 31, 2010	4,371,586	70,943
Accretion to redemption value	—	201
Balance, December 31, 2011	4,371,586	$	71,144

Equity

12 Months Ended

Dec. 31, 2011

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 New York Stock Exchange (“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, 2011, there were issued and outstanding 222,972,708 Common Units representing an aggregate 99.69% 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, 2011, 2010 and 2009 was as follows:



	Years Ended December 31,
	2011	2010	2009
Number of Common Units, beginning of period	222,941,172	222,898,248	222,829,956
Issuance of restricted Common Units under long-term incentive plan	31,536	42,924	68,292
Number of Common Units, end of period	222,972,708	222,941,172	222,898,248

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 partner’s capital of $153.0 million, $352.3 million and $97.0 million for the years ended December 31, 2011, 2010 and 2009, 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 ETP Common Units ⁽¹⁾	Price per ETP Unit		Net Proceeds		Use of Proceeds
January 2009	6,900,000	$	34.05	$	225,354	(2)
April 2009	9,775,000	37.55		352,369		(3)
October 2009	6,900,000	41.27		275,979		(2)
January 2010	9,775,000	44.72		423,551		(2)(3)
August 2010	10,925,000	46.22		489,418		(2)(3)
April 2011	14,202,500	50.52		695,496		(3)
November 2011	15,237,500	44.67		660,241		(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’s Equity Distribution Program

In December 2010, ETP entered into an Equity Distribution Agreement with Credit Suisse Securities (USA) LLC (“Credit Suisse”). According to the provisions of this agreement, ETP may offer and sell from time to time through Credit Suisse, as its sales agent, ETP Common Units having an aggregate offering price of up to $200 million. Sales of the units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between ETP and Credit Suisse. Under the terms of this agreement, ETP may also sell ETP Common Units to Credit Suisse as principal for its own account at a price agreed upon at the time of sale. Any sale of ETP Common Units to Credit Suisse as principal would be pursuant to the terms of a separate agreement between ETP and Credit Suisse.

Previously, ETP had an Equity Distribution Agreement with UBS Securities LLC ("UBS"), which was similar to its existing agreement with Credit Suisse as described above. During 2010, ETP received proceeds from units issued pursuant to this agreement of approximately $214.3 million, net of commissions, which proceeds were used to repay amounts outstanding under its revolving credit facility.

During 2011, ETP received proceeds from units issued pursuant to this agreement of approximately $96.3 million, net of commissions, which proceeds were used for general partnership purposes. Approximately $69.6 million of ETP Common Units remain available to be issued under the agreement based on trades initiated through December 31, 2011.

ETP's Distribution Reinvestment Program

In April 2011, ETP filed a registration statement with the SEC covering its Distribution Reinvestment Plan (the “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 2011, distributions of approximately $15.0 million were reinvested under the DRIP resulting in the issuance of 353,679 ETP Common Units.

Sale of Common Units by Regency

In October 2011, Regency issued 11,500,000 Regency Common Units through a public offering. The proceeds, net of commissions, of approximately $231.9 million were used to repay borrowings outstanding under the Regency Credit Facility.

In May 2011, Regency issued 8,500,001 Regency Common Units in a private placement. The net proceeds of $203.9 million were used to fund a portion of Regency’s 30% ownership interest in Lone Star, as discussed in Note 3.

In August 2010, Regency issued 17,537,500 Regency Common Units through a public offering. The proceeds of $400.2 million, net of commissions, from the offering were used primarily to repay borrowings under the Regency Credit Facility.

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. ETP GP was required to contribute approximately $12.3 million for the years ended December 31, 2009. As of December 31, 2009, ETP GP had a contribution payable to ETP of $8.9 million, which was paid in full in 2010.

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. We currently have no independent operations outside of our direct and indirect interests in ETP and Regency.

Our distributions declared during the years ended December 31, 2011, 2010 and 2009 are summarized as follows:



Quarter Ended	Record Date	Payment Date	Distribution per ETE Common Unit
September 30, 2011	November 4, 2011	November 18, 2011	$	0.6250
June 30, 2011	August 5, 2011	August 19, 2011	0.6250
March 31, 2011	May 6, 2011	May 19, 2011	0.5600
December 31, 2010	February 7, 2011	February 18, 2011	0.5400

September 30, 2010	November 8, 2010	November 19, 2010	$	0.5400
June 30, 2010	August 9, 2010	August 19, 2010	0.5400
March 31, 2010	May 7, 2010	May 19, 2010	0.5400
December 31, 2009	February 8, 2010	February 19, 2010	0.5400

September 30, 2009	November 9, 2009	November 19, 2009	$	0.5350
June 30, 2009	August 7, 2009	August 19, 2009	0.5350
March 31, 2009	May 8, 2009	May 19, 2009	0.5250
December 31, 2008	February 6, 2009	February 19, 2009	0.5100

On January 25, 2012, the Parent Company declared a cash distribution for the three months ended December 31, 2011 of $0.625 per Common Unit, or $2.50 annualized. We paid this distribution on February 17, 2012 to Unitholders of record at the close of business on February 7, 2012.

The total amount of distributions we have declared is as follows (all from Available Cash from our operating surplus and are shown in the period to which they relate):



	Years Ended December 31,
	2011		2010		2009
Limited Partners	$	542,939	$	481,554	$	475,911
General Partner interest	1,685		1,495		1,478
Total ETE distributions	$	544,624	$	483,049	$	477,389

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
September 30, 2011	November 4, 2011	November 14, 2011	$	0.89375
June 30, 2011	August 5, 2011	August 15, 2011	0.89375
March 31, 2011	May 6, 2011	May 16, 2011	0.89375
December 31, 2010	February 7, 2011	February 14, 2011	0.89375

September 30, 2010	November 8, 2010	November 15, 2010	$	0.89375
June 30, 2010	August 9, 2010	August 16, 2010	0.89375
March 31, 2010	May 7, 2010	May 17, 2010	0.89375
December 31, 2009	February 8, 2010	February 15, 2010	0.89375

September 30, 2009	November 9, 2009	November 16, 2009	$	0.89375
June 30, 2009	August 7, 2009	August 14, 2009	0.89375
March 31, 2009	May 8, 2009	May 15, 2009	0.89375
December 31, 2008	February 6, 2009	February 13, 2009	0.89375

On January 25, 2012, ETP declared a cash distribution for the three months ended December 31, 2011 of $0.89375 per ETP Common Unit, or $3.575 annualized. ETP paid this distribution on February 14, 2012 to ETP Unitholders of record at the close of business on February 7, 2012.

The total amounts of ETP distributions declared during the periods presented in the consolidated financial statements are as follows (all from Available Cash from ETP’s operating surplus and are shown in the period to which they relate):



	Years Ended December 31,
	2011		2010		2009
Limited Partners:
Common Units	$	762,350	$	676,798	$	629,263
Class E Units	12,484		12,484		12,484
General Partner interest	19,603		19,524		19,505
Incentive Distribution Rights	421,888		375,979		350,486
Total ETP distributions	$	1,216,325	$	1,084,785	$	1,011,738

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, 2011	November 7, 2011	November 14, 2011	$	0.455
June 30, 2011	August 5, 2011	August 12, 2011	0.450
March 31, 2011	May 6, 2011	May 13, 2011	0.445
December 31, 2010	February 7, 2011	February 14, 2011	0.445

September 30, 2010	November 5, 2010	November 12, 2010	$	0.445
June 30, 2010	August 6, 2010	August 13, 2010	0.445

On January 26, 2012, Regency declared a cash distribution for the three months ended December 31, 2011 of $0.46 per Regency Common Unit, or $1.84 annualized. Regency paid this distribution on February 13, 2012 to Regency Unitholders of record at the close of business on February 6, 2012.

The total amounts of Regency distributions declared since the date of acquisition were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):



	Years Ended December 31,
	2011		2010
Limited Partners	$	274,538	$	175,360
General Partner interest	5,185		3,640
Incentive Distribution Rights	6,057		3,016
Total Regency distributions	$	285,780	$	182,016

Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:



	December 31,
	2011			2010
Net gains on commodity related hedges	$	1,696		$	14,146
Unrealized gains on available-for-sale securities	114			918
Subtotal	1,810			15,064
Amounts attributable to noncontrolling interest	(1,132		)	(10,266		)
Total AOCI included in partners' capital, net of tax	$	678		$	4,798

- Definition

The entire disclosure for the formation, structure, control and ownership of the partnership. Disclosures related to accounts comprising partners' capital. Includes balances of general partners' capital account, limited partners' capital account, preferred partners' capital account and total partners' capital account and units outstanding; accumulated other comprehensive income; amount and nature of changes to amount of partner's capital and units outstanding by class, rights and privileges for each class of units; distribution policies and distributions paid by unit class; impact of and correction of an error in previously issued financial statements; limitations of partners' liability; redemption, conversion and distribution policies; and deferred compensation related to the issuance of units.

+ References + Details

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

12 Months Ended

Dec. 31, 2011

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES:

Regulatory Matter

On September 21, 2011, in lieu of filing a new general rate case filing under Section 4 of the NGA, Transwestern filed a proposed settlement with the FERC, which was approved by the FERC on October 31, 2011. Transwestern is required to file a new general rate case on October 1, 2014. However, shippers which were not parties to the settlement have the right to challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint.

Guarantee — Fayetteville Express Pipeline LLC

Fayetteville Express Pipeline LLC (“FEP”), a joint venture entity in which ETP owns a 50% interest, had a credit agreement that provided for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP guaranteed 50% of the obligations of FEP under the FEP Facility, with the remainder of FEP Facility obligations guaranteed by Kinder Morgan Energy Partners, L.P. (“KMP”). Amounts borrowed under the FEP Facility bore interest at a rate based on either a Eurodollar rate or Prime Rate.

In July 2011, the FEP Facility was repaid with capital contributions from ETP and KMP totaling $390 million along with proceeds from a $600 million term loan credit facility maturing in July 2012 (which can be extended for one year at the option of FEP). Upon closing and funding of the term loan facility, the FEP Facility was terminated. FEP also entered into a $50 million revolving credit facility maturing in July 2015. FEP's indebtedness under its new credit facilities is not guaranteed by ETP or KMP.

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.

NGL Pipeline Regulation

ETP and Regency have interests in NGL pipelines located in Texas. ETP and Regency believe that these pipelines do not provide interstate service and that they are thus not subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. We cannot guarantee that the jurisdictional status of ETP’s and Regency’s NGL facilities will remain unchanged; however, should they be found jurisdictional, the FERC’s rate-making methodologies may limit ETP’s and Regency’s ability to set rates based on their actual costs, may delay or limit the use of rates that reflect increased costs and may subject ETP and Regency to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.

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. ETP has several propane purchase and supply commitments, which are typically one year agreements with varying terms as to quantities, prices and expiration dates. ETP believes 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 2029. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $29.3 million, $23.8 million and $19.8 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Future minimum lease commitments for such leases are:



Years Ending December 31:
2012	$	22,480
2013	20,667
2014	17,467
2015	17,292
2016	17,283
Thereafter	152,473

Amounts reflected above do not include future minimum lease commitments for ETP's propane operations, which were deconsolidated in January 2012 in connection with the contribution of ETP's propane operations 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 propane are flammable, combustible gases. 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, 2011 and 2010, accruals of approximately $18.2 million and $10.2 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, 2011 or 2010 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

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 operations are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the U.S. Department of Transportation (“DOT”). We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.

ETP Environmental Matters

ETP has 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 ETP’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, ETP believes that such costs will not have a material adverse effect on its financial position.

As of December 31, 2011 and 2010, accruals related to ETP on an undiscounted basis of $13.7 million and $13.8 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities related to environmental matters.

Based on information available at this time and reviews undertaken to identify potential exposure, ETP believes the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by polychlorinated biphenyls (“PCBs”). The costs of this work are not eligible for recovery in rates. ETP’s total accrued future estimated cost of remediation activities expected to continue through 2025 is $5.7 million, which is included in the aggregate environmental accruals discussed above. Transwestern received approval from the FERC for the continuation of rate recovery of projected soil and groundwater remediation costs not related to PCBs for the term of its rate case settlement.

Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

The U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of ETP’s facilities. ETP expects 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 ETP believes such costs will not have a material adverse effect on its financial position, results of operations or cash flows.

Petroleum-based contamination or other environmental wastes are known to be located on or adjacent to six sites on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. ETP has not been named as a potentially responsible party at any of these sites, and ETP believes that its operations have not contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our December 31, 2011 or 2010 consolidated balance sheets. Based on information currently available to us, the presence of contamination and remediation activities at these sites are not expected to have a material adverse effect on our financial condition or results of operations.

On August 20, 2010, the EPA published new regulations under the federal Clean Air Act ("CAA") to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require ETP 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, ETP would not expect that the cost to comply with the rule's requirements will have a material adverse effect on its 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 ETP to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if it replaces equipment or expands existing facilities in the future. At this point, ETP is not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes ETP might make in the future.

ETP’s pipeline operations are subject to regulation by the DOT under the Pipeline Hazardous Materials Safety Administration (“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. For the years ended December 31, 2011, 2010 and 2009, $18.3 million, $13.3 million and $31.4 million, respectively, of capital costs and $14.7 million, $15.4 million and $18.5 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Price Risk Management Assets And Liabilities

12 Months Ended

Dec. 31, 2011

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 natural gas and NGL 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 holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price. ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities.). At the inception of the hedge, ETP will 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 ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP will value the hedged natural gas inventory at current spot market prices along with the financial derivative it uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of its derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that it recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdrawal of natural gas.

ETP is also exposed to market risk on natural gas it retains for fees in its intrastate transportation and storage operations and operational gas sales in its interstate transportation operations. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statements of operations.

During the fourth quarter of 2011, ETP's trading activities included the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to ETP's transportation and storage segment's operations and are accounted for in cost of products sold in our consolidated statement of operations. As a result of ETP's trading activities and the use of derivative financial instruments in ETP's transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attempts to manage this volatility through the use of daily position and profit and loss reports provided to its risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in ETP's commodity risk management policy.

Derivatives are utilized in ETP’s midstream operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. ETP attempts to maintain balanced positions in its marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide most of the gas required by its long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. To the extent that financial contracts are not tied to physical delivery, are expected to be offset with financial contracts to balance ETP’s positions. To the extent open commodity positions exist, fluctuating commodity prices can impact its financial position and results of operations, either favorably or unfavorably.

ETP’s propane operations permitted customers to guarantee the propane delivery price for the next heating season. As ETP executed fixed sales price contracts with its customers, it entered into propane futures contracts to fix the purchase price related to these sales contracts, thereby locking in a gross profit margin. Additionally, ETP used propane futures contracts to secure the purchase price of its propane inventory for a percentage of its anticipated propane sales.

The following table details ETP’s outstanding commodity-related derivatives:



	December 31, 2011			December 31, 2010
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu) - trading ⁽¹⁾	(151,260,000	)	2012-2013	—		—
Basis Swaps IFERC/NYMEX (MMBtu) - non-trading	(61,420,000	)	2012-2013	(38,897,500	)	2011
Swing Swaps IFERC (MMBtu)	92,370,000		2012-2013	(19,720,000	)	2011
Fixed Swaps/Futures (MMBtu)	797,500		2012	(2,570,000	)	2011
Forward Physical Contracts (MMBtu)	(10,672,028	)	2012	—		—
Options — Calls (MMBtu)	—		—	(3,000,000	)	2011
Propane:
Forwards/Swaps (Gallons)	38,766,000		2012-2013	1,974,000		2011
Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)	(28,752,500	)	2012	(28,050,000	)	2011
Fixed Swaps/Futures (MMBtu)	(45,822,500	)	2012	(39,105,000	)	2011
Hedged Item — Inventory (MMBtu)	45,822,500		2012	39,105,000		2011
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)	—		—	(210,000	)	2011
Options — Puts (MMBtu)	3,600,000		2012	26,760,000		2011-2012
Options — Calls (MMBtu)	(3,600,000	)	2012	(26,760,000	)	2011-2012
Propane:
Forwards/Swaps (Gallons)	—		—	32,466,000		2011

⁽¹⁾ Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana and Henry Hub locations.

We expect gains of $6.4 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:



	December 31, 2011		December 31, 2010
	Notional Volume	Maturity	Notional Volume	Maturity
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)	2,198,000	2012	3,830,000	2011
Propane:
Forwards/Swaps (Gallons)	11,802,000	2012-2013	18,648,000	2011-2012
Natural Gas Liquids:
Forwards/Swaps (Barrels)	533,000	2012-2013	1,212,110	2011-2012
Options - Puts (Barrels)	110,000	2012	—	—
WTI Crude Oil:
Forwards/Swaps (Barrels)	350,000	2012-2014	373,655	2011-2012

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. Upon the de-designation of these trades Regency has $4.8 million in net hedging losses in accumulated other comprehensive income which will be amortized to earnings over the next 2.25 years, of which $5.2 million will be reclassified into 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, 2011, none of which are designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

December 31, 2011

December 31, 2010

ETP

May 2012 ⁽²⁾

Forward starting to pay a fixed rate of 2.59% and receive a floating rate

350,000

—

ETP

August 2012⁽²⁾

Forward starting to pay a fixed rate of 3.51% and receive a floating rate

500,000

400,000

ETP

July 2013 ⁽²⁾

Forward starting to pay a fixed rate of 4.02% and receive a floating rate

300,000

—

ETP

July 2018

Pay a floating rate plus a spread of 4.01% and receive a fixed rate of 6.70%

500,000

Regency

April 2012

Pay a fixed rate of 1.325% and receive a floating rate

250,000


⁽¹⁾	Floating rates are based on LIBOR.


⁽²⁾	Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.

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 $66.4 million of realized losses on terminated interest rate swaps that had been accounted for as cash flow hedges. In addition to the $66.4 million of realized losses on hedged interest rate swaps, ETE also paid $102.2 million to terminate non-hedged interest rate swaps. The $102.2 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 $168.6 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 $66.2 million and $52.2 million as of December 31, 2011 and 2010, 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.

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, 2011 and 2010:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	2011		2010		2011			2010
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	77,197	$	35,031	$	(819	)	$	(6,631	)
Commodity derivatives	4,539		9,263		(10,128		)	(14,692		)
	81,736		44,294		(10,947		)	(21,323		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	227,337	$	64,940	$	(251,268	)	$	(72,729	)
Commodity derivatives	1,017		275		(4,844		)	—
Interest rate derivatives	36,301		20,790		(117,490		)	(20,922		)
Embedded derivatives in Regency Preferred Units	—		—		(39,049		)	(57,023		)
	264,655		86,005		(412,651		)	(150,674		)
Total derivatives	$	346,391	$	130,299	$	(423,598	)	$	(171,997	)

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/liabilities.”

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,
	2011		2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	6,369	$	49,665		$	3,143
Interest rate derivatives	—		(29,980		)	(14,705		)
Total	$	6,369	$	19,685		$	(11,562	)



	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Years Ended December 31,
		2011		2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	18,685	$	37,325		$	9,924
Interest rate derivatives	Interest expense, net	—		(86,697		)	(26,882		)
Total		$	18,685	$	(49,372	)	$	(16,958	)



	Location of Gain/(Loss) Reclassified from AOCI into Income (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
		Years Ended December 31,
		2011		2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	286	$	(70	)	$	—
Total		$	286	$	(70	)	$	—



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Years Ended December 31,
		2011		2010		2009
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	34,000	$	16,210	$	60,045
Total		$	34,000	$	16,210	$	60,045



	Location of Gain/ (Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2011			2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives – non-trading	Cost of products sold	$	9,199		$	3,806		$	99,807
Commodity derivatives – trading	Cost of products sold	(29,777		)	—			—
Interest rate derivatives	Gains (losses) on non-hedged interest rate derivatives	(77,804		)	(52,357		)	33,619
Embedded derivatives	Other income (expense)	17,974			(8,390		)	—
Total		$	(80,408	)	$	(56,941	)	$	133,426

We recognized $20.8 million, $70.5 million and $18.6 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships and amounts classified as trading activity) for the years ended December 31, 2011, 2010 and 2009, respectively. In addition, for the years ended December 31, 2011, 2010 and 2009, we recognized unrealized gains of $9.5 million, $17.4 million and $48.6 million, respectively, on commodity derivatives and related hedged inventory accounted for as fair value hedges.

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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+ Details

Retirement Benefits	12 Months Ended
Retirement Benefits	Dec. 31, 2011
Compensation and Retirement Disclosure [Abstract]
Retirement Benefits	RETIREMENT BENEFITS: We have a 401(k) savings plan which covers 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 $14.0 million, $9.8 million and $9.8 million to the 401(k) savings plan for the years ended December 31, 2011, 2010 and 2009, 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 $2.0 million to its own 401(k) savings plan for period from May 26, 2010 to December 31, 2010.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
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-Subparagraph b
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+ Details

Related Party Transactions

12 Months Ended

Dec. 31, 2011

Related Party Transactions

RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. For the year ended December 31, 2011 and from May 26, 2010 to December 31, 2010 the Parent Company received $16.6 million and $5.8 million, respectively, from Regency related to these services. For the years ended December 31, 2011, 2010 and 2009, the Parent Company paid $17.1 million, $6.3 million and $0.5 million, respectively, to ETP related to these services. The increase in payments to ETP was the result of increased service fees related to the provision of various general and administrative services for Regency. The management fees received from Regency for the year ended December 31, 2011 include the reimbursement of various general and administrative services of $6.6 million for expenses incurred by ETP on behalf of Regency. These amounts have been eliminated in our consolidated financial statements.

On January 18, 2012, Enterprise Products Partners L.P. ("Enterprise") sold a significant portion of its ownership in our limited partner interest. Subsequent to that transaction Enterprise owns less than 5% of our outstanding common units. Prior to this transaction, Enterprise and its affiliates were considered related parties for financial reporting purposes.

ETP and Enterprise transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines and ETP sells natural gas and compression equipment to Enterprise. ETP’s propane operations routinely buy and sell product with Enterprise. Regency sells natural gas and NGLs to, and incurs NGL processing fees with Enterprise. ETP’s propane operations purchase a portion of its propane requirements from Enterprise pursuant to an agreement that expires in March 2015, and includes an option to extend the agreement for an additional year. The following table presents sales to and purchases from Enterprise, including Regency transactions subsequent to May 26, 2010:



	Years Ended December 31,
	2011		2010		2009
ETP’s Natural Gas Operations:
Sales	$	654,129	$	538,657	$	414,333
Purchases	26,992		23,592		48,528
Regency’s Natural Gas Operations:
Sales	376,542		142,631		—
Purchases	9,427		4,606		—
ETP’s Propane Operations:
Sales	10,613		15,527		19,961
Purchases	471,046		415,897		343,540

As of December 31, 2011 and 2010, Titan, had forward mark-to-market derivatives for approximately 38.8 million and 1.7 million gallons of propane at a fair value liability of $4.1 million and a fair value asset of $0.2 million, respectively, with Enterprise. In addition, as of December 31, 2010, Titan had forward derivatives accounted for as cash flow hedges of 32.5 million gallons of propane at a fair value asset of $6.6 million with Enterprise. ETP’s propane operations discontinued cash flow hedge accounting in July 2011; therefore, all of their forward derivatives are currently accounted for using mark-to-market accounting.

For the year ended December 31, 2011 revenue of $1.9 million and cost of products sold of $1.2 million are included in our consolidated statements of operations related to transactions with FEP, ETP’s unconsolidated affiliate. For the year ended December 31, 2010 revenue of $26.0 million and cost of products sold of $20.5 million are included in our consolidated statements of operations related to transactions with FEP, ETP’s unconsolidated affiliate.

Under a master services agreement with HPC, Regency operates and provides all employees and services for the operation and management of HPC. The related party general administrative expenses reimbursed to Regency were $16.8 million and $9.8 million, respectively, for year ended December 31, 2011 and for the period from May 26, 2010 to December 31, 2010.

The following table summarizes the related party balances on our consolidated balance sheets:



	As of December 31,
	2011				2010
Accounts receivable from related parties:
Enterprise:
ETP’s Natural Gas Operations	$	54,644			$	36,736
Regency’s Natural Gas Operations	41,781				25,539
ETP’s Propane Operations	—				2,327
Other	3,981				11,729
Total accounts receivable from related parties	$	100,406		76,331,000	$	76,331
Accounts payable to related parties:
Enterprise:
ETP’s Natural Gas Operations	$	2,198			$	2,687
Regency’s Natural Gas Operations	1,469				1,323
ETP’s Propane Operations	27,770				22,985
Other	1,771				356
Total accounts payable to related parties	$	33,208			$	27,351
ETP’s net imbalance receivable from (payable to) Enterprise	$	(780	)		$	1,360
Regency’s net imbalance receivable from Enterprise	$	2,008			$	753

Effective August 17, 2009, ETP acquired 100% of the membership interests of ETG, which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”). ETT provides compression services to customers engaged in the transportation of natural gas, including ETP. The membership interests of ETG were contributed to ETP by its Chief Executive Officer and by two entities, one of which is controlled by a director of the General Partner of ETP’s general partner and the other of which is controlled by a member of ETP’s management. In exchange, the former members acquired the right to receive (in cash or Common Units) future amounts to be determined based on the terms of the contribution arrangement. These contingent amounts are to be determined in 2014 and 2017, and the former members of ETG may receive payments contingent on the acquired operations performing at a level above the average return required by ETP for approval of its own growth projects during the period since acquisition. In addition, the former members may be required to make cash payments to ETP under certain circumstances. ETP has not accrued any contingent payments related to this agreement.

Subsequent to the acquisition of ETG, ETP is obligated to pay $4.7 million in operating lease payments per year to the former owners for the use of compressor equipment through 2017.

- Definition

The entire disclosure for related party transactions, including the nature of the relationship(s), a description of the transactions, the amount of the transactions, the effects of any change in the method of establishing the terms of the transaction from the previous period, stated interest rate, expiration date, terms and manner of settlement per the agreement with the related party, and amounts due to or from related parties. If the entity and one or more other entities are under common ownership or management control and this control affects the operating results or financial position, disclosure includes the nature of the control relationship even if there are no transactions between the entities. Disclosure may also include the aggregate amount of current and deferred tax expense for each statement of earnings presented where the entity is a member of a group that files a consolidated tax return, the amount of any tax related balances due to or from affiliates as of the date of each statement of financial position presented, the principal provisions of the method by which the consolidated amount of current and deferred tax expense is allocated to the members of the group and the nature and effect of any changes in that method. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References

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-Number 210
-Article 4
-Section 08
-Paragraph k

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-Number 210
-Article 3A
-Section 04
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+ Details

Reportable Segments

12 Months Ended

Dec. 31, 2011

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

As a result of the Regency Transactions in May 2010, our reportable segments were re-evaluated and currently reflect two reportable segments, both of which conduct their business exclusively in the United States of America, as follows:


•	Investment in ETP - Reflects the consolidated operations of ETP.


•	Investment in Regency - Reflects the consolidated operations of Regency.

Each of the respective general partners of ETP and Regency have separate operating management and boards of directors. We control ETP and Regency through our ownership of their respective general partners. See further discussion of ETP and Regency’s operations in Note 1.

We evaluate the performance of our operating segments based on net income. The following tables present financial information by segment. The amounts reflected as “Corporate and Other” include the Parent Company activity and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

ETP and Regency related party transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

The following tables present the financial information by segment for the following periods:



	Investment in ETP		Investment in Regency			Corporate and Other			Adjustments and Eliminations			Total
Year Ended December 31, 2011
Revenues from external customers	$	6,812,431	$	1,425,859		$	—		$	2,413		$	8,240,703
Intersegment revenues	38,009		8,039			—			(46,048		)	—
Depreciation and amortization	430,904		168,684			12,221			—			611,809
Interest expense, net of interest capitalized	474,113		102,474			163,622			(398		)	739,811
Equity in earnings of affiliates	25,836		119,540			—			(28,188		)	117,188
Income tax expense (benefit)	18,815		465			(2,397		)	—			16,883
Net income (loss)	697,162		73,619			(214,346		)	(28,188		)	528,247
Year Ended December 31, 2010
Revenues from external customers	$	5,884,786	$	715,324		$	—		$	(1,978	)	$	6,598,132
Intersegment revenues	41		1,289			—			(1,330		)	—
Depreciation and amortization	343,011		75,967			12,221			—			431,199
Interest expense, net of interest capitalized	412,553		48,251			167,669			(3,586		)	624,887
Equity in earnings of affiliates	11,727		53,493			—			—			65,220
Income tax expense (benefit)	15,536		552			(2,350		)	—			13,738
Net income (loss)	617,222		(5,972		)	(274,670		)	—			336,580
Year Ended December 31, 2009
Revenues from external customers	$	5,417,295	$	—		$	—		$	—		$	5,417,295
Intersegment revenues	—		—			—			—			—
Depreciation and amortization	312,803		—			12,221			—			325,024
Interest expense, net of interest capitalized	394,274		—			74,146			—			468,420
Equity in earnings of affiliates	20,597		—			—			—			20,597
Income tax expense (benefit)	12,777		—			(3,548		)	—			9,229
Net income (loss)	791,542		—			(93,671		)	—			697,871



	As of December 31,
	2011			2010			2009
Total assets:
Investment in ETP	$	15,518,616		$	12,149,992		$	11,734,972
Investment in Regency	5,567,856			4,770,204			—
Corporate and Other	470,086			469,221			431,109
Adjustments and Eliminations	(659,765		)	(10,687		)	(5,572		)
Total	$	20,896,793		$	17,378,730		$	12,160,509



	Years Ended December 31,
	2011		2010		2009
Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
Investment in ETP ⁽¹⁾	$	2,921,865	$	1,470,001	$	680,780
Investment in Regency ⁽²⁾	410,814		2,068,328		—
Total	$	3,332,679	$	3,538,329	$	680,780

⁽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,
	2011			2010		2009
Advances to and investments in affiliates:
Investment in ETP	$	200,612		$	8,723	$	663,298
Investment in Regency	1,924,705			1,351,256		—
Adjustments and Eliminations	(628,717		)	—		—
Total	$	1,496,600		$	1,359,979	$	663,298

The following tables provide revenues, grouped by similar products and services, for both ETP and Regency. These amounts include transactions between ETP and Regency.

Investment in ETP



	Years Ended December 31,
	2011		2010		2009
Intrastate Transportation and Storage	$	2,397,887	$	2,075,217	$	1,773,528
Interstate Transportation	446,743		292,419		270,213
Midstream	2,041,600		1,955,627		2,060,451
NGL Transportation and Services	362,701		—		—
Retail Propane and Other Retail Propane Related	1,468,082		1,419,646		1,292,583
All Other	133,427		141,918		20,520
Total revenues	$	6,850,440	$	5,884,827	$	5,417,295

Investment in Regency



	Years Ended December 31,
	2011		2010		2009
Gathering and Processing	$	1,226,260	$	606,944	$	—
Joint Ventures	—		—		—
Contract Compression	150,496		86,099		—
Contract Treating	39,604		13,662		—
Corporate and Others	17,538		9,908		—
Total revenues	$	1,433,898	$	716,613	$	—

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
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+ Details

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2011

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. ETP’s propane operations are 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.



	Quarter Ended
	March 31		June 30			September 30			December 31		Total Year
2011:
Revenues	$	1,989,120	$	1,974,906		$	2,097,866		$	2,178,811	$	8,240,703
Gross margin	787,694		710,754			744,829			814,427		3,057,704
Operating income	364,243		260,561			270,008			340,007		1,234,819
Net income	199,092		106,652			60,699			161,804		528,247
Limited Partners’ interest in net income	88,366		66,080			68,869			85,537		308,852
Basic net income per limited partner unit	$	0.40	$	0.30		$	0.31		$	0.38	$	1.39
Diluted net income per limited partner unit	$	0.40	$	0.30		$	0.31		$	0.38	$	1.38
2010:
Revenues	$	1,871,981	$	1,362,529		$	1,587,807		$	1,775,815	$	6,598,132
Gross margin	647,116		522,075			592,702			724,902		2,486,795
Operating income	338,928		179,257			202,052			316,492		1,036,729
Net income (loss)	204,082		(20,479		)	(4,826		)	157,803		336,580
Limited Partners’ interest in net income (loss)	112,428		19,208			(15,289		)	75,814		192,161
Basic net income (loss) per limited partner unit	$	0.50	$	0.09		$	(0.07	)	$	0.34	$	0.86
Diluted net income (loss) per limited partner unit	$	0.50	$	0.09		$	(0.07	)	$	0.34	$	0.86

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

Supplemental Financial Statement Information

12 Months Ended

Dec. 31, 2011

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,
	2011		2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	18,460	$	27,247
Accounts receivable from related companies	1,456		171
Other current assets	714		864
Total current assets	20,630		28,282
ADVANCES TO AND INVESTMENTS IN AFFILIATES	2,225,572		2,231,722
INTANGIBLES AND OTHER ASSETS, net	49,906		29,118
Total assets	$	2,296,108	$	2,289,122
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	174	$	—
Accounts payable to related companies	12,334		6,654
Accrued and other current liabilities	35,706		44,200
Total current liabilities	48,214		50,854
LONG-TERM DEBT, less current maturities	1,871,500		1,800,000
SERIES A CONVERTIBLE PREFERRED UNITS	322,910		317,600

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
General Partner	321		520
Limited Partners – Common Unitholders (222,972,708 and 222,941,172 units authorized, issued and outstanding at December 31, 2011 and 2010, respectively)	52,485		115,350
Accumulated other comprehensive income	678		4,798
Total partners’ capital	53,484		120,668
Total liabilities and partners’ capital	$	2,296,108	$	2,289,122

STATEMENTS OF OPERATIONS



	Years Ended December 31,
	2011			2010			2009
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(29,641	)	$	(21,829	)	$	(4,970	)
OTHER INCOME (EXPENSE):
Interest expense	(163,612		)	(167,658		)	(74,049		)
Equity in earnings of affiliates	509,361			455,901			526,383
Losses on non-hedged interest rate derivatives	—			(53,388		)	(5,620		)
Other, net	(5,796		)	(19,721		)	79
INCOME BEFORE INCOME TAXES	310,312			193,305			441,823
Income tax expense (benefit)	501			547			(650		)
NET INCOME	309,811			192,758			442,473
GENERAL PARTNER’S INTEREST IN NET INCOME	959			597			1,370
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	308,852		$	192,161		$	441,103

STATEMENTS OF CASH FLOWS



	Years Ended December 31,
	2011			2010			2009
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	469,004		$	317,328		$	468,969
CASH FLOWS FROM INVESTING ACTIVITIES:
MEP Transaction	—			3,258			—
Net cash provided by investing activities	—			3,258			—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	91,500			1,858,245			67,505
Principal payments on debt	(20,000		)	(1,632,374		)	(65,816		)
Distributions to partners	(525,596		)	(483,048		)	(470,658		)
Debt issuance costs	(23,695		)	(36,224		)	—
Net cash used in financing activities	(477,791		)	(293,401		)	(468,969		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(8,787		)	27,185			—
CASH AND CASH EQUIVALENTS, beginning of period	27,247			62			62
CASH AND CASH EQUIVALENTS, end of period	$	18,460		$	27,247		$	62

- Definition

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

+ References + Details

Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)	12 Months Ended
	Dec. 31, 2011
Accounting Policies [Abstract]
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 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. Investment in ETP Revenues for ETP’s sales of natural gas, NGLs including propane, and propane appliances, parts, and fittings 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. Tank rent is recognized ratably over the period it is earned. ETP’s intrastate transportation and storage and interstate transportation operations’ results are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, ETP’s 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. ETP’s 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, ETP purchases natural gas from the market, including purchases from ETP’s midstream marketing operations, and from producers at the wellhead. In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in its storage facilities. ETP also engages in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover its carrying costs and provide for a gross profit margin. ETP expects 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, ETP 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 it operates, competitive factors in the energy industry, and other issues. Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through its pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and gross margins principally under fee-based or other arrangements in which it receives 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 ETP’s systems and is not directly dependent on commodity prices. ETP also utilizes other types of arrangements in its 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 ETP 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, and (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s 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. ETP conducts marketing activities in which it markets the natural gas that flows through its assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells 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. ETP’s retail propane operations sell propane and propane-related products and services. The Heritage Operating, L.P. (“HOLP”) and Titan Energy Partners, L.P. (“Titan”) customer base includes residential, commercial, industrial and agricultural customers. In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. Investment in Regency 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 Certain of our subsidiaries are subject to regulation by certain state and federal authorities and have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us 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 all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheets for the period in which the discontinuance of regulatory accounting treatment occurs.
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.
Marketable Securities	Marketable Securities Marketable securities are classified as available-for-sale securities and are reflected as current assets on the consolidated balance sheets at fair value.
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 valued at the lower of cost or market utilizing the weighted-average cost method. Propane inventories are also valued at the lower of cost or market utilizing the weighted-average cost of propane delivered to the customer service locations, including storage fees and inbound freight costs. 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 Federal Energy Regulatory Commission (“FERC”) mandated lives of the assets. 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. No impairment of long-lived assets was required during the periods presented. Capitalized interest is included for pipeline construction projects, except for interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of ETP’s revolving credit facility 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.
Advances to and Investments in Affiliates	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.
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. Goodwill In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”), which simplified how entities test goodwill for impairment. ASU 2011-08 gives entities the option, under certain circumstances, to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. ASU 2011-08 was effective for fiscal years beginning after December 15, 2011, and early adoption was permitted. We adopted and applied this standard to our annual impairment tests performed for certain reporting units during the year ended December 31, 2011. There was no material impact to our financial position or results of operations as a result of the adoption of this standard. 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 December 31 for reporting units within ETP's interstate transportation and NGL transportation and services operations and for all of Regency's reporting units. Our annual impairment test is performed as of August 31 for all other reporting units. No goodwill impairments were recorded for the periods presented in these consolidated financial statements.
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. Our annual impairment test is performed as of August 31 for reporting units within ETP and as of December 31 for Regency’s reporting units. 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 Our subsidiaries have determined that they are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates. However, ETP’s and Regency’s management were not able to reasonably measure the fair value of the asset retirement obligations as of December 31, 2011 or 2010 because the settlement dates were indeterminable. ETP and Regency will record an asset retirement obligation in the periods in which management can reasonably determine the settlement dates.
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. Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 2011 was $12.21 billion and $11.37 billion, respectively. As of December 31, 2010, the aggregate fair value and carrying amount of our consolidated debt obligations was $10.23 billion and $9.38 billion, respectively. 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. ETP’s shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and totaled $40.4 million, $43.3 million and $55.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. ETP does not separately charge propane shipping and handling costs to customers.
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, storage fees and inbound freight on propane, 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, shipping and handling costs related to propane, 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.
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 a change in partners’ capital.
Income Taxes	Income Taxes ETE is a limited partnership. 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 limited partnership, we are generally not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualifying income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the years ended December 31, 2011, 2010 and 2009, our non-qualifying income did not exceed the statutory limit. Those subsidiaries which are taxable corporations follow the asset and liability method of accounting for income taxes, under which deferred income taxes are recorded based upon differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled. The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level.
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 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 Accumulated Other Comprehensive Income (“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.
Allocation of Income (Loss)	Allocation of Income (Loss) 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 (Tables)

12 Months Ended

Dec. 31, 2011

Operations And Organization [Abstract]

Schedule Of Equity Interests

At December 31, 2011, our equity interests consisted of:



	General Partner Interest (as a % of total partnership interest)		Incentive Distribution Rights (“IDRs”)		Limited Partner Units
ETP	1.5	%	100	%	50,226,967
Regency	1.8	%	100	%	26,266,791

Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

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) included in cash flows from operating activities was comprised as follows:



	Years Ended December 31,
	2011			2010			2009
Accounts receivable	$	6,073		$	92,085		$	28,431
Accounts receivable from related companies	(23,816		)	(26,265		)	(26,321		)
Inventories	50,991			14,750			(101,592		)
Exchanges receivable	620			1,064			22,074
Other current assets	(51,398		)	33,233			8,195
Other non-current assets	7,077			5,843			(1,467		)
Accounts payable	21,452			(66,936		)	(16,024		)
Accounts payable to related companies	5,857			(9,939		)	4,184
Exchanges payable	1,954			(3,841		)	(35,433		)
Accrued and other current liabilities	84,704			72,669			(101,927		)
Other non-current liabilities	(118		)	442			1,401
Price risk management assets and liabilities, net	54,752			146,438			(130,157		)
Net change in operating assets and liabilities, net of effects of acquisitions	$	158,148		$	259,543		$	(348,636	)

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,
	2011		2010		2009
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	225,827	$	108,076	$	46,134
Gain from subsidiary common unit transactions	$	153,039	$	352,307	$	96,996
NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued from acquisitions	$	4,166	$	1,242,604	$	26,237
Subsidiary issuance of Common Units in connection with certain acquisitions	$	3,000	$	584,436	$	63,339
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	728,112	$	547,286	$	440,492
Cash paid for income taxes	$	26,603	$	9,188	$	15,447

Schedule of Inventory

Inventories consisted of the following:



	December 31,
	2011		2010
Natural gas and NGLs, excluding propane	$	146,132	$	170,179
Propane	86,958		76,341
Appliances, parts and fittings and other	94,873		119,864
Total inventories	$	327,963	$	366,384

Other Current Assets

Other current assets consisted of the following:



	December 31,
	2011		2010
Deposits paid to vendors	$	66,231	$	52,192
Prepaid and other	115,673		57,167
Total other current assets	$	181,904	$	109,359

Property, Plant and Equipment

Components and useful lives of property, plant and equipment were as follows:



	December 31,
	2011			2010
Land and improvements	$	137,352		$	103,325
Buildings and improvements (10 to 83 years)	278,829			383,274
Pipelines and equipment (10 to 83 years)	11,358,550			9,709,568
Natural gas and NGL storage facilities (40 years) ⁽¹⁾	789,612			100,909
Bulk storage, equipment and facilities (5 to 83 years)	976,882			736,520
Tanks and other equipment (10 to 30 years)	643,527			623,126
Vehicles (3 to 33 years)	230,609			200,702
Right of way (20 to 83 years)	793,232			637,930
Furniture and fixtures (3 to 33 years)	48,466			41,205
Linepack	58,982			55,744
Pad gas	57,907			57,907
Other (5 to 33 years)	234,440			189,103
Construction work-in-process	920,951			445,117
	16,529,339			13,284,430
Less - Accumulated depreciation	(1,970,777		)	(1,431,698		)
Property, plant and equipment, net	$	14,558,562		$	11,852,732

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,
	2011		2010		2009
Depreciation expense	$	556,569	$	394,698	$	304,129
Capitalized interest, excluding AFUDC	$	12,630	$	4,071	$	11,791

Schedule of Goodwill

Changes in the carrying amount of goodwill were as follows:



	Investment in ETP			Investment in Regency		Corporate and Other		Total
Balance, December 31, 2009	$	745,505		$	—	$	29,589	$	775,094
Goodwill acquired	36,460			789,789		—		826,249
Other	(732		)	—		—		(732		)
Balance, December 31, 2010	781,233			789,789		29,589		1,600,611
Goodwill acquired	438,364			—		—		438,364
Balance, December 31, 2011	$	1,219,597		$	789,789	$	29,589	$	2,038,975

Components And Useful Lives Of Intangibles And Other Assets

Components and useful lives of intangible assets were as follows:



	December 31, 2011					December 31, 2010
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	1,058,662	$	(134,909	)	$	971,657	$	(88,583	)
Trade names (20 years)	65,500		(5,185		)	65,500		(1,910		)
Noncompete agreements (3 to 15 years)	15,431		(7,835		)	21,165		(11,888		)
Patents (9 years)	750		(201		)	750		(118		)
Other (10 to 15 years)	1,320		(581		)	1,320		(492		)
Total amortizable intangible assets	1,141,663		(148,711		)	1,060,392		(102,991		)
Non-amortizable intangible assets:
Trademarks	79,339		—			77,445		—
Total intangible assets	$	1,221,002	$	(148,711	)	$	1,137,837	$	(102,991	)

Aggregate Amortization Expense Of Intangibles And Other Assets

e amortization expense of intangibles assets was as follows:



	Years Ended December 31,
	2011		2010		2009
Reported in depreciation and amortization	$	54,655	$	35,602	$	20,895

Estimate

Estimated Aggregate Amortization Expense

Estimated aggregate amortization expense of intangible assets for the next five years was as follows:



Years Ending December 31:
2012	$	44,793
2013	40,871
2014	39,746
2015	39,746
2016	39,746

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,
	2011		2010
Unamortized financing costs (3 to 30 years)	$	132,375	$	98,067
Regulatory assets	88,993		92,939
Other	27,542		34,575
Total other non-current assets, net	$	248,910	$	225,581

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	December 31,
	2011		2010
Interest payable	$	204,182	$	191,466
Customer advances and deposits	100,525		111,448
Accrued capital expenditures	228,877		87,260
Accrued wages and benefits	80,205		76,592
Taxes payable other than income taxes	79,331		36,204
Income taxes payable	14,781		8,344
Other	56,011		56,374
Total accrued and other current liabilities	$	763,912	$	567,688

Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis



	Fair Value Measurements at December 31, 2011 Using
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	1,229		$	1,229		$	—		$	—
Interest rate derivatives	36,301			—			36,301			—
Commodity derivatives:
Condensate — Forward Swaps	538			—			538			—
Natural Gas:
Basis Swaps IFERC/NYMEX	62,924			62,924			—			—
Swing Swaps IFERC	15,002			1,687			13,315			—
Fixed Swaps/Futures	218,479			214,572			3,907			—
Options — Puts	6,435			—			6,435			—
Forward Physical Swaps	699			—			699			—
NGLs:
Forward Swaps	94			—			94			—
Options — Puts	309			—			309			—
Propane — Forward Swaps	9			—			9			—
Total commodity derivatives	304,489			279,183			25,306			—
Total Assets	$	342,019		$	280,412		$	61,607		$	—
Liabilities:
Interest rate derivatives	$	(117,490	)	$	—		$	(117,490	)	$	—
Series A Convertible Preferred Units	(322,910		)	—			—			(322,910		)
Embedded derivatives in the Regency Preferred Units	(39,049		)	—			—			(39,049		)
Commodity derivatives:
Condensate — Forward Swaps	(1,567		)	—			(1,567		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(82,290		)	(82,290		)	—			—
Swing Swaps IFERC	(16,074		)	(3,061		)	(13,013		)	—
Fixed Swaps/Futures	(148,111		)	(148,111		)	—			—
Options — Calls	(12		)	—			(12		)	—
Forward Physical Swaps	(712		)	—			(712		)	—
NGLs — Forward Swaps	(8,561		)	—			(8,561		)	—
Propane — Forward Swaps	(4,131		)	—			(4,131		)	—
Total commodity derivatives	(261,458		)	(233,462		)	(27,996		)	—
Total Liabilities	$	(740,907	)	$	(233,462	)	$	(145,486	)	$	(361,959	)



	Fair Value Measurements at December 31, 2010 Using
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	2,032		$	2,032		$	—		$	—
Interest rate derivatives	20,790			—			20,790			—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	15,756			15,756			—			—
Swing Swaps IFERC	1,682			1,562			120			—
Fixed Swaps/Futures	44,955			42,474			2,481			—
Options — Calls	75			—			75			—
Options — Puts	26,241			—			26,241			—
NGLs — Forward Swaps	192			—			192			—
Propane — Forward Swaps	6,864			—			6,864			—
Total commodity derivatives	95,765			59,792			35,973			—
Total Assets	$	118,587		$	61,824		$	56,763		$	—
Liabilities:
Interest rate derivatives	$	(20,922	)	$	—		$	(20,922	)	$	—
Series A Convertible Preferred Units	(317,600		)	—			—			(317,600		)
Embedded derivatives in the Regency Preferred Units	(57,023		)	—			—			(57,023		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(17,372		)	(17,372		)	—			—
Swing Swaps IFERC	(3,768		)	(3,520		)	(248		)	—
Fixed Swaps/Futures	(42,252		)	(41,825		)	(427		)	—
Options — Calls	(2,643		)	—			(2,643		)	—
Options — Puts	(7		)	—			(7		)	—
NGLs — Forward Swaps	(10,684		)	—			(10,684		)	—
WTI Crude Oil	(3,581		)	—			(3,581		)	—
Total commodity derivatives	(80,307		)	(62,717		)	(17,590		)	—
Total Liabilities	$	(475,852	)	$	(62,717	)	$	(38,512	)	$	(374,623	)

Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis



Net liability balance, December 31, 2010	$	(374,623	)
Net unrealized gains included in other income (expense)	12,664
Net liability balance, December 31, 2011	$	(361,959	)

Components Of Federal And State Income Tax

The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows:



	Years Ended December 31,
	2011			2010		2009
Current expense (benefit):
Federal	$	(842	)	$	1,602	$	(8,850	)
State	16,883			8,594		9,657
Total	16,041			10,196		807
Deferred expense (benefit):
Federal	416			2,788		8,643
State	426			754		(221		)
Total	842			3,542		8,422
Total income tax expense	$	16,883		$	13,738	$	9,229

Regency [Member]

Acquired Finite-Lived Intangible Assets [Line Items]

Schedule of Finite-Lived Intangible Assets Acquired as Part of Business Combination

We recorded the following intangible assets in conjunction with the Regency Transactions:



Amortizable intangible assets:
Customer relationships, contracts and agreements (30 years)	$	600,860
Trade names (20 years)	65,500
Total intangible and other assets acquired	$	666,360

Acquisitions and Related Transactions (Tables)

12 Months Ended

Dec. 31, 2011

Business Acquisition [Line Items]

Pro Forma Results Of Operations



	Years Ended December 31,
	2011		2010
Revenues	$	8,349,292	$	7,406,943
Net income	520,034		347,572
Net income attributable to partners	307,809		228,206
Basic net income per Limited Partner unit	$	1.38	$	1.02
Diluted net income per Limited Partner unit	$	1.38	$	1.02

LDH [Member]

Business Acquisition [Line Items]

Schedule Of Assets Acquired And Liabilities Assumed

The following table summarizes the assets acquired and liabilities assumed recognized as of the acquisition date:



Total current assets	$	118,177
Property, plant and equipment⁽¹⁾	1,419,591
Goodwill	432,026
Intangible assets	81,000
Other assets	157
	2,050,951

Total current liabilities	74,964
Other long-term liabilities	438
	75,402
Total consideration	1,975,549
Cash received	31,231
Total consideration, net of cash received	$	1,944,318


⁽¹⁾	Property, plant and equipment (and estimated useful lives) acquired in the LDH Acquisition consisted of the following:



Land and improvements	$	30,759
Buildings and improvements (10 to 40 years)	3,123
Pipelines and equipment (20 to 65 years)	662,881
Natural gas liquids storage (40 years)	682,419
Linepack	704
Vehicles (3 to 20 years)	242
Furniture and fixtures (3 to 10 years)	49
Other (5 to 10 years)	8,526
Construction work-in-process	30,888
Property, plant and equipment	$	1,419,591

Schedule Of Components Of Property, Plant And Equipment Acquired

Property, plant and equipment (and estimated useful lives) acquired in the LDH Acquisition consisted of the following:



Land and improvements	$	30,759
Buildings and improvements (10 to 40 years)	3,123
Pipelines and equipment (20 to 65 years)	662,881
Natural gas liquids storage (40 years)	682,419
Linepack	704
Vehicles (3 to 20 years)	242
Furniture and fixtures (3 to 10 years)	49
Other (5 to 10 years)	8,526
Construction work-in-process	30,888
Property, plant and equipment	$	1,419,591

Regency [Member]

Business Acquisition [Line Items]

Schedule Of Assets Acquired And Liabilities Assumed

The following summarizes the assets acquired and liabilities assumed in the Regency Transactions, as well as the fair value of the noncontrolling interest in Regency:



Total current assets	$	189,502
Property, plant and equipment	1,548,384
Advances to and investments in affiliates	739,164
Goodwill	789,789
Intangible assets	666,360
Other assets	37,693
	3,970,892
Total current liabilities	192,788
Long-term debt	1,239,863
Other long-term liabilities	57,517
Regency convertible preferred units	70,793
Noncontrolling interest	2,104,981
	3,665,942
Total consideration	304,950
Cash received	23,995
Total consideration, net of cash received	$	280,955

Schedule Of Components Of Property, Plant And Equipment Acquired

We recorded the following intangible assets in conjunction with the Regency Transactions:



Amortizable intangible assets:
Customer relationships, contracts and agreements (30 years)	$	600,860
Trade names (20 years)	65,500
Total intangible and other assets acquired	$	666,360

- Definition

Tabular disclosure of pro forma results of operations for a material business acquisition or series of individually immaterial business acquisitions that are material in the aggregate.

+ References + Details

- Definition

Tabular disclosure of a material business combination completed during the period, including background, timing, and recognized assets and liabilities. This table does not include leveraged buyouts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 51
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 52
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Appendix F
-Paragraph F4
-Subparagraph e

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1392-128463

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-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1486-128463

+ Details

Invesment in Affiliates (Tables)

12 Months Ended

Dec. 31, 2011

Investment In Affiliates [Abstract]

Schedule Of Aggregated Selected Balance Sheet And Income Statement Data For Our Unconsolidated Affiliates

-rich Bone Spring and Avalon shale formations in West Texas. The project consists of two plants, a 25 MMcf/d refrigeration plant and a 100 MMcf/d cryogenic processing plant. The initial start-up of the refrigeration unit is expected to be in service by the second quarter of 2012, with full facilities available by the fourth quarter of 2012.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, MEP, HPC and FEP (on a 100% basis for all periods presented).



	December 31,
	2011		2010
Current assets	$	88,583	$	83,735
Property, plant and equipment, net	3,987,460		4,052,396
Other assets	152,904		160,655
Total assets	$	4,228,947	$	4,296,786
Current liabilities	$	83,989	$	91,860
Non-current liabilities	1,478,499		1,772,686
Equity	2,666,459		2,432,240
Total liabilities and equity	$	4,228,947	$	4,296,786



	Years Ended December 31,
	2011		2010		2009
Revenue	$	569,116	$	406,346	$	142,076
Operating income	324,686		221,623		66,333
Net income	242,316		166,910		56,247

Net Income Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2011

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,
	2011			2010			2009
Basic Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	308,852		$	192,161		$	441,103
Weighted average limited partner units	222,968,261			222,941,156			222,898,203
Basic net income per limited partner unit	$	1.39		$	0.86		$	1.98
Diluted Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	308,852		$	192,161		$	441,103
Dilutive effect of Unit Grants	(620		)	(228		)	(410		)
Diluted net income available to limited partners	$	308,232		$	191,933		$	440,693
Weighted average limited partner units	222,968,261			222,941,156			222,898,203
Diluted net income per limited partner unit	$	1.38		$	0.86		$	1.98

Debt Obligations Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Debt Instrument [Line Items]

Schedule of debt obligations

Our debt obligations consist of the following:



	December 31,
	2011			2010
Parent Company Indebtedness:
ETE Senior Notes, due October 15, 2020	$	1,800,000		$	1,800,000
ETE Senior Secured Revolving Credit Facility	71,500			—
Subsidiary Indebtedness:
ETP Senior Notes:
5.65% Senior Notes due August 1, 2012	400,000			400,000
6.0% Senior Notes due July 1, 2013	350,000			350,000
8.5% Senior Notes due April 15, 2014	350,000			350,000
5.95% Senior Notes due February 1, 2015	750,000			750,000
6.125% Senior Notes due February 15, 2017	400,000			400,000
6.7% Senior Notes due July 1, 2018	600,000			600,000
9.7% Senior Notes due March 15, 2019	600,000			600,000
9.0% Senior Notes due April 15, 2019	650,000			650,000
4.65% Senior Notes due June 1, 2021	800,000			—
6.625% Senior Notes due October 15, 2036	400,000			400,000
7.5% Senior Notes due July 1, 2038	550,000			550,000
6.05% Senior Notes due June 1, 2041	700,000			—
Regency Senior Notes:
9.375% Senior Notes due June 1, 2016	250,000			250,000
6.875% Senior Notes due December 1, 2018	600,000			600,000
6.5% Senior Notes due July 15, 2021	500,000			—
Transwestern Senior Unsecured Notes:
5.39% Senior Notes due November 17, 2014	88,000			88,000
5.54% Senior Notes due November 17, 2016	125,000			125,000
5.64% Senior Notes due May 24, 2017	82,000			82,000
5.36% Senior Notes due December 9, 2020	175,000			175,000
5.89% Senior Notes due May 24, 2022	150,000			150,000
5.66% Senior Notes due December 9, 2024	175,000			175,000
6.16% Senior Notes due May 24, 2037	75,000			75,000
HOLP Senior Secured Notes:
Senior Secured Notes with interest rates ranging from 7.26% to 8.87%	71,314			103,127
Revolving Credit Facilities:
ETP Revolving Credit Facility	314,438			402,327
Regency Revolving Credit Facility	332,000			285,000
Other Long-Term Debt	10,434			9,671
Unamortized discounts, net	(10,309		)	(6,013		)
Fair value adjustments related to interest rate swaps	11,647			17,260
	11,371,024			9,381,372
Current maturities	(424,160		)	(35,305		)
	$	10,946,864		$	9,346,067

Future maturities of long-term debt

These amounts exclude (i) maturities of long-term debt related to ETP's Propane Business, which was contributed to AmeriGas in January 2012 (see Note 3), and (ii) $1.3 million in net unamortized discounts and fair value adjustments related to interest rate swaps:



2012	$	400,043
2013	350,046
2014	770,000
2015	821,500
2016	689,438
Thereafter	8,257,000
Total	$	11,288,027

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

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-Publisher FASB
-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

+ Details

Redeemable Preferred Units (Tables)

12 Months Ended

Dec. 31, 2011

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 Preferred Units	Amount
Balance at date of Acquisition	4,371,586	$	70,793
Accretion to redemption value	—	150
Balance, December 31, 2010	4,371,586	70,943
Accretion to redemption value	—	201
Balance, December 31, 2011	4,371,586	$	71,144

- Definition

Tabular disclosure of preferred units of master limited partnerships that have priority over limited partner units in areas including liquidation, redemption, conversion, tax status of distribution or sharing in distributions. This schedule ordinarily includes a description of the preferred units that details various rights including redemption, conversion, liquidation, and sharing in distributions; capital contributed by preferred partners; number of preferred units authorized to be issued, issued, and outstanding; aggregate cumulative cash distributions made to the preferred partners; aggregate cumulative net income earned by the preferred partners; capital account balance of the preferred partners.

+ References + Details

Equity (Tables)

12 Months Ended

Dec. 31, 2011

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 ETP Common Units ⁽¹⁾	Price per ETP Unit		Net Proceeds		Use of Proceeds
January 2009	6,900,000	$	34.05	$	225,354	(2)
April 2009	9,775,000	37.55		352,369		(3)
October 2009	6,900,000	41.27		275,979		(2)
January 2010	9,775,000	44.72		423,551		(2)(3)
August 2010	10,925,000	46.22		489,418		(2)(3)
April 2011	14,202,500	50.52		695,496		(3)
November 2011	15,237,500	44.67		660,241		(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.

Change In ETE Common Units

The change in ETE Common Units during the years ended December 31, 2011, 2010 and 2009 was as follows:



	Years Ended December 31,
	2011	2010	2009
Number of Common Units, beginning of period	222,941,172	222,898,248	222,829,956
Issuance of restricted Common Units under long-term incentive plan	31,536	42,924	68,292
Number of Common Units, end of period	222,972,708	222,941,172	222,898,248

Accumulated Other Comprehensive Income (Loss)

The following table presents the components of AOCI, net of tax:



	December 31,
	2011			2010
Net gains on commodity related hedges	$	1,696		$	14,146
Unrealized gains on available-for-sale securities	114			918
Subtotal	1,810			15,064
Amounts attributable to noncontrolling interest	(1,132		)	(10,266		)
Total AOCI included in partners' capital, net of tax	$	678		$	4,798

Parent Company [Member]

Quarterly Distributions Of Available Cash

Our distributions declared during the years ended December 31, 2011, 2010 and 2009 are summarized as follows:



Quarter Ended	Record Date	Payment Date	Distribution per ETE Common Unit
September 30, 2011	November 4, 2011	November 18, 2011	$	0.6250
June 30, 2011	August 5, 2011	August 19, 2011	0.6250
March 31, 2011	May 6, 2011	May 19, 2011	0.5600
December 31, 2010	February 7, 2011	February 18, 2011	0.5400

September 30, 2010	November 8, 2010	November 19, 2010	$	0.5400
June 30, 2010	August 9, 2010	August 19, 2010	0.5400
March 31, 2010	May 7, 2010	May 19, 2010	0.5400
December 31, 2009	February 8, 2010	February 19, 2010	0.5400

September 30, 2009	November 9, 2009	November 19, 2009	$	0.5350
June 30, 2009	August 7, 2009	August 19, 2009	0.5350
March 31, 2009	May 8, 2009	May 19, 2009	0.5250
December 31, 2008	February 6, 2009	February 19, 2009	0.5100

The total amount of distributions we have declared is as follows (all from Available Cash from our operating surplus and are shown in the period to which they relate):



	Years Ended December 31,
	2011		2010		2009
Limited Partners	$	542,939	$	481,554	$	475,911
General Partner interest	1,685		1,495		1,478
Total ETE distributions	$	544,624	$	483,049	$	477,389

ETP [Member]

Quarterly Distributions Of Available Cash



	Years Ended December 31,
	2011		2010		2009
Limited Partners:
Common Units	$	762,350	$	676,798	$	629,263
Class E Units	12,484		12,484		12,484
General Partner interest	19,603		19,524		19,505
Incentive Distribution Rights	421,888		375,979		350,486
Total ETP distributions	$	1,216,325	$	1,084,785	$	1,011,738

ETP’s distributions declared during the periods presented below are summarized as follows:



Quarter Ended	Record Date	Payment Date	Distribution per ETP Common Unit
September 30, 2011	November 4, 2011	November 14, 2011	$	0.89375
June 30, 2011	August 5, 2011	August 15, 2011	0.89375
March 31, 2011	May 6, 2011	May 16, 2011	0.89375
December 31, 2010	February 7, 2011	February 14, 2011	0.89375

September 30, 2010	November 8, 2010	November 15, 2010	$	0.89375
June 30, 2010	August 9, 2010	August 16, 2010	0.89375
March 31, 2010	May 7, 2010	May 17, 2010	0.89375
December 31, 2009	February 8, 2010	February 15, 2010	0.89375

September 30, 2009	November 9, 2009	November 16, 2009	$	0.89375
June 30, 2009	August 7, 2009	August 14, 2009	0.89375
March 31, 2009	May 8, 2009	May 15, 2009	0.89375
December 31, 2008	February 6, 2009	February 13, 2009	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, 2011	November 7, 2011	November 14, 2011	$	0.455
June 30, 2011	August 5, 2011	August 12, 2011	0.450
March 31, 2011	May 6, 2011	May 13, 2011	0.445
December 31, 2010	February 7, 2011	February 14, 2011	0.445

September 30, 2010	November 5, 2010	November 12, 2010	$	0.445
June 30, 2010	August 6, 2010	August 13, 2010	0.445



	Years Ended December 31,
	2011		2010
Limited Partners	$	274,538	$	175,360
General Partner interest	5,185		3,640
Incentive Distribution Rights	6,057		3,016
Total Regency distributions	$	285,780	$	182,016

- Definition

The entire disclosure for comprehensive income. Includes, but is not limited to, the following: 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income. Components of comprehensive income include: (1) foreign currency translation adjustments; (2) gains (losses) on foreign currency transactions that are designated as, and are effective as, economic hedges of a net investment in a foreign entity; (3) gains (losses) on intercompany foreign currency transactions that are of a long-term-investment nature, when the entities to the transaction are consolidated, combined, or accounted for by the equity method in the reporting enterprise's financial statements; (4) change in the market value of a futures contract that qualifies as a hedge of an asset reported at fair value; (5) unrealized holding gains (losses) on available-for-sale securities and that resulting from transfers of debt securities from the held-to-maturity category to the available-for-sale category; (6) a net loss recognized as an additional pension liability not yet recognized as net periodic pension cost; and (7) the net gain (loss) and net prior service cost or credit for pension plans and other postretirement benefit plans.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 14-26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e637-108580

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e681-108580

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e653-108580

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187085-122770

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e709-108580

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 55
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6920433&loc=d3e998-108581

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e640-108580

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e716-108580

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e689-108580

+ Details

Unit-Based Compensation Plans Unit-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2011

Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]

Schedule Of ETP Awards Granted To Employees And Non-Employee Directos



	Number of ETP Units		Weighted Average Grant-Date Fair Value Per ETP Unit
Unvested awards as of December 31, 2010	1,936,578		$	43.95
Awards granted	1,386,251		48.35
Awards vested	(610,557	)	44.07
Awards forfeited	(148,563	)	42.74
Unvested awards as of December 31, 2011	2,563,709		46.37

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)

12 Months Ended

Dec. 31, 2011

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

Future minimum lease commitments for such leases are:



Years Ending December 31:
2012	$	22,480
2013	20,667
2014	17,467
2015	17,292
2016	17,283
Thereafter	152,473

Price Risk Management Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2011

Interest Rate Swaps Outstanding

The following is a summary of interest rate swaps outstanding as of December 31, 2011, none of which are designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

December 31, 2011

December 31, 2010

ETP

May 2012 ⁽²⁾

Forward starting to pay a fixed rate of 2.59% and receive a floating rate

350,000

—

ETP

August 2012⁽²⁾

Forward starting to pay a fixed rate of 3.51% and receive a floating rate

500,000

400,000

ETP

July 2013 ⁽²⁾

Forward starting to pay a fixed rate of 4.02% and receive a floating rate

300,000

—

ETP

July 2018

Pay a floating rate plus a spread of 4.01% and receive a fixed rate of 6.70%

500,000

Regency

April 2012

Pay a fixed rate of 1.325% and receive a floating rate

250,000


⁽¹⁾	Floating rates are based on LIBOR.


⁽²⁾	Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.

Fair Value Of Derivative Instruments

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of December 31, 2011 and 2010:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	2011		2010		2011			2010
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	77,197	$	35,031	$	(819	)	$	(6,631	)
Commodity derivatives	4,539		9,263		(10,128		)	(14,692		)
	81,736		44,294		(10,947		)	(21,323		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	227,337	$	64,940	$	(251,268	)	$	(72,729	)
Commodity derivatives	1,017		275		(4,844		)	—
Interest rate derivatives	36,301		20,790		(117,490		)	(20,922		)
Embedded derivatives in Regency Preferred Units	—		—		(39,049		)	(57,023		)
	264,655		86,005		(412,651		)	(150,674		)
Total derivatives	$	346,391	$	130,299	$	(423,598	)	$	(171,997	)

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,
	2011		2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	6,369	$	49,665		$	3,143
Interest rate derivatives	—		(29,980		)	(14,705		)
Total	$	6,369	$	19,685		$	(11,562	)

Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized



	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Years Ended December 31,
		2011		2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	18,685	$	37,325		$	9,924
Interest rate derivatives	Interest expense, net	—		(86,697		)	(26,882		)
Total		$	18,685	$	(49,372	)	$	(16,958	)



	Location of Gain/(Loss) Reclassified from AOCI into Income (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
		Years Ended December 31,
		2011		2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	286	$	(70	)	$	—
Total		$	286	$	(70	)	$	—



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Years Ended December 31,
		2011		2010		2009
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	34,000	$	16,210	$	60,045
Total		$	34,000	$	16,210	$	60,045



	Location of Gain/ (Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2011			2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives – non-trading	Cost of products sold	$	9,199		$	3,806		$	99,807
Commodity derivatives – trading	Cost of products sold	(29,777		)	—			—
Interest rate derivatives	Gains (losses) on non-hedged interest rate derivatives	(77,804		)	(52,357		)	33,619
Embedded derivatives	Other income (expense)	17,974			(8,390		)	—
Total		$	(80,408	)	$	(56,941	)	$	133,426

ETP [Member]

Outstanding Commodity-Related Derivatives

The following table details ETP’s outstanding commodity-related derivatives:



	December 31, 2011			December 31, 2010
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu) - trading ⁽¹⁾	(151,260,000	)	2012-2013	—		—
Basis Swaps IFERC/NYMEX (MMBtu) - non-trading	(61,420,000	)	2012-2013	(38,897,500	)	2011
Swing Swaps IFERC (MMBtu)	92,370,000		2012-2013	(19,720,000	)	2011
Fixed Swaps/Futures (MMBtu)	797,500		2012	(2,570,000	)	2011
Forward Physical Contracts (MMBtu)	(10,672,028	)	2012	—		—
Options — Calls (MMBtu)	—		—	(3,000,000	)	2011
Propane:
Forwards/Swaps (Gallons)	38,766,000		2012-2013	1,974,000		2011
Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)	(28,752,500	)	2012	(28,050,000	)	2011
Fixed Swaps/Futures (MMBtu)	(45,822,500	)	2012	(39,105,000	)	2011
Hedged Item — Inventory (MMBtu)	45,822,500		2012	39,105,000		2011
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)	—		—	(210,000	)	2011
Options — Puts (MMBtu)	3,600,000		2012	26,760,000		2011-2012
Options — Calls (MMBtu)	(3,600,000	)	2012	(26,760,000	)	2011-2012
Propane:
Forwards/Swaps (Gallons)	—		—	32,466,000		2011

Regency [Member]

Outstanding Commodity-Related Derivatives

The following table details Regency’s outstanding commodity-related derivatives:



	December 31, 2011		December 31, 2010
	Notional Volume	Maturity	Notional Volume	Maturity
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)	2,198,000	2012	3,830,000	2011
Propane:
Forwards/Swaps (Gallons)	11,802,000	2012-2013	18,648,000	2011-2012
Natural Gas Liquids:
Forwards/Swaps (Barrels)	533,000	2012-2013	1,212,110	2011-2012
Options - Puts (Barrels)	110,000	2012	—	—
WTI Crude Oil:
Forwards/Swaps (Barrels)	350,000	2012-2014	373,655	2011-2012

- Definition

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

+ References + Details

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5579245-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5624171-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41678-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41638-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5580258-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41641-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
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-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

+ Details

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2011

The following table presents sales to and purchases from Enterprise, including Regency transactions subsequent to May 26, 2010:



	Years Ended December 31,
	2011		2010		2009
ETP’s Natural Gas Operations:
Sales	$	654,129	$	538,657	$	414,333
Purchases	26,992		23,592		48,528
Regency’s Natural Gas Operations:
Sales	376,542		142,631		—
Purchases	9,427		4,606		—
ETP’s Propane Operations:
Sales	10,613		15,527		19,961
Purchases	471,046		415,897		343,540

Related Party Receivables And Payables

The following table summarizes the related party balances on our consolidated balance sheets:



	As of December 31,
	2011				2010
Accounts receivable from related parties:
Enterprise:
ETP’s Natural Gas Operations	$	54,644			$	36,736
Regency’s Natural Gas Operations	41,781				25,539
ETP’s Propane Operations	—				2,327
Other	3,981				11,729
Total accounts receivable from related parties	$	100,406		76,331,000	$	76,331
Accounts payable to related parties:
Enterprise:
ETP’s Natural Gas Operations	$	2,198			$	2,687
Regency’s Natural Gas Operations	1,469				1,323
ETP’s Propane Operations	27,770				22,985
Other	1,771				356
Total accounts payable to related parties	$	33,208			$	27,351
ETP’s net imbalance receivable from (payable to) Enterprise	$	(780	)		$	1,360
Regency’s net imbalance receivable from Enterprise	$	2,008			$	753

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2011

Operating Segments [Member]

Financial Information By Segment

The following tables present the financial information by segment for the following periods:



	Investment in ETP		Investment in Regency			Corporate and Other			Adjustments and Eliminations			Total
Year Ended December 31, 2011
Revenues from external customers	$	6,812,431	$	1,425,859		$	—		$	2,413		$	8,240,703
Intersegment revenues	38,009		8,039			—			(46,048		)	—
Depreciation and amortization	430,904		168,684			12,221			—			611,809
Interest expense, net of interest capitalized	474,113		102,474			163,622			(398		)	739,811
Equity in earnings of affiliates	25,836		119,540			—			(28,188		)	117,188
Income tax expense (benefit)	18,815		465			(2,397		)	—			16,883
Net income (loss)	697,162		73,619			(214,346		)	(28,188		)	528,247
Year Ended December 31, 2010
Revenues from external customers	$	5,884,786	$	715,324		$	—		$	(1,978	)	$	6,598,132
Intersegment revenues	41		1,289			—			(1,330		)	—
Depreciation and amortization	343,011		75,967			12,221			—			431,199
Interest expense, net of interest capitalized	412,553		48,251			167,669			(3,586		)	624,887
Equity in earnings of affiliates	11,727		53,493			—			—			65,220
Income tax expense (benefit)	15,536		552			(2,350		)	—			13,738
Net income (loss)	617,222		(5,972		)	(274,670		)	—			336,580
Year Ended December 31, 2009
Revenues from external customers	$	5,417,295	$	—		$	—		$	—		$	5,417,295
Intersegment revenues	—		—			—			—			—
Depreciation and amortization	312,803		—			12,221			—			325,024
Interest expense, net of interest capitalized	394,274		—			74,146			—			468,420
Equity in earnings of affiliates	20,597		—			—			—			20,597
Income tax expense (benefit)	12,777		—			(3,548		)	—			9,229
Net income (loss)	791,542		—			(93,671		)	—			697,871

Investment In ETP [Member]

Investment in ETP



	Years Ended December 31,
	2011		2010		2009
Intrastate Transportation and Storage	$	2,397,887	$	2,075,217	$	1,773,528
Interstate Transportation	446,743		292,419		270,213
Midstream	2,041,600		1,955,627		2,060,451
NGL Transportation and Services	362,701		—		—
Retail Propane and Other Retail Propane Related	1,468,082		1,419,646		1,292,583
All Other	133,427		141,918		20,520
Total revenues	$	6,850,440	$	5,884,827	$	5,417,295

Investment In Regency [Member]

Investment in Regency



	Years Ended December 31,
	2011		2010		2009
Gathering and Processing	$	1,226,260	$	606,944	$	—
Joint Ventures	—		—		—
Contract Compression	150,496		86,099		—
Contract Treating	39,604		13,662		—
Corporate and Others	17,538		9,908		—
Total revenues	$	1,433,898	$	716,613	$	—

Assets Segments [Member]

Financial Information By Segment



	As of December 31,
	2011			2010			2009
Total assets:
Investment in ETP	$	15,518,616		$	12,149,992		$	11,734,972
Investment in Regency	5,567,856			4,770,204			—
Corporate and Other	470,086			469,221			431,109
Adjustments and Eliminations	(659,765		)	(10,687		)	(5,572		)
Total	$	20,896,793		$	17,378,730		$	12,160,509

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,
	2011		2010		2009
Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
Investment in ETP ⁽¹⁾	$	2,921,865	$	1,470,001	$	680,780
Investment in Regency ⁽²⁾	410,814		2,068,328		—
Total	$	3,332,679	$	3,538,329	$	680,780

⁽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,
	2011			2010		2009
Advances to and investments in affiliates:
Investment in ETP	$	200,612		$	8,723	$	663,298
Investment in Regency	1,924,705			1,351,256		—
Adjustments and Eliminations	(628,717		)	—		—
Total	$	1,496,600		$	1,359,979	$	663,298

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References + Details

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

industry, and other issues.



	Quarter Ended
	March 31		June 30			September 30			December 31		Total Year
2011:
Revenues	$	1,989,120	$	1,974,906		$	2,097,866		$	2,178,811	$	8,240,703
Gross margin	787,694		710,754			744,829			814,427		3,057,704
Operating income	364,243		260,561			270,008			340,007		1,234,819
Net income	199,092		106,652			60,699			161,804		528,247
Limited Partners’ interest in net income	88,366		66,080			68,869			85,537		308,852
Basic net income per limited partner unit	$	0.40	$	0.30		$	0.31		$	0.38	$	1.39
Diluted net income per limited partner unit	$	0.40	$	0.30		$	0.31		$	0.38	$	1.38
2010:
Revenues	$	1,871,981	$	1,362,529		$	1,587,807		$	1,775,815	$	6,598,132
Gross margin	647,116		522,075			592,702			724,902		2,486,795
Operating income	338,928		179,257			202,052			316,492		1,036,729
Net income (loss)	204,082		(20,479		)	(4,826		)	157,803		336,580
Limited Partners’ interest in net income (loss)	112,428		19,208			(15,289		)	75,814		192,161
Basic net income (loss) per limited partner unit	$	0.50	$	0.09		$	(0.07	)	$	0.34	$	0.86
Diluted net income (loss) per limited partner unit	$	0.50	$	0.09		$	(0.07	)	$	0.34	$	0.86

Supplemental Financial Statement Information (Tables)

12 Months Ended

Dec. 31, 2011

Schedule Of Statements Of Cash Flows

Non-cash investing and financing activities and supplemental cash flow information were as follows:



	Years Ended December 31,
	2011		2010		2009
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	225,827	$	108,076	$	46,134
Gain from subsidiary common unit transactions	$	153,039	$	352,307	$	96,996
NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued from acquisitions	$	4,166	$	1,242,604	$	26,237
Subsidiary issuance of Common Units in connection with certain acquisitions	$	3,000	$	584,436	$	63,339
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	728,112	$	547,286	$	440,492
Cash paid for income taxes	$	26,603	$	9,188	$	15,447

Parent Company [Member]

Schedule Of Balance Sheets

BALANCE SHEETS



	December 31,
	2011		2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	18,460	$	27,247
Accounts receivable from related companies	1,456		171
Other current assets	714		864
Total current assets	20,630		28,282
ADVANCES TO AND INVESTMENTS IN AFFILIATES	2,225,572		2,231,722
INTANGIBLES AND OTHER ASSETS, net	49,906		29,118
Total assets	$	2,296,108	$	2,289,122
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	174	$	—
Accounts payable to related companies	12,334		6,654
Accrued and other current liabilities	35,706		44,200
Total current liabilities	48,214		50,854
LONG-TERM DEBT, less current maturities	1,871,500		1,800,000
SERIES A CONVERTIBLE PREFERRED UNITS	322,910		317,600

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
General Partner	321		520
Limited Partners – Common Unitholders (222,972,708 and 222,941,172 units authorized, issued and outstanding at December 31, 2011 and 2010, respectively)	52,485		115,350
Accumulated other comprehensive income	678		4,798
Total partners’ capital	53,484		120,668
Total liabilities and partners’ capital	$	2,296,108	$	2,289,122

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS



	Years Ended December 31,
	2011			2010			2009
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(29,641	)	$	(21,829	)	$	(4,970	)
OTHER INCOME (EXPENSE):
Interest expense	(163,612		)	(167,658		)	(74,049		)
Equity in earnings of affiliates	509,361			455,901			526,383
Losses on non-hedged interest rate derivatives	—			(53,388		)	(5,620		)
Other, net	(5,796		)	(19,721		)	79
INCOME BEFORE INCOME TAXES	310,312			193,305			441,823
Income tax expense (benefit)	501			547			(650		)
NET INCOME	309,811			192,758			442,473
GENERAL PARTNER’S INTEREST IN NET INCOME	959			597			1,370
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	308,852		$	192,161		$	441,103

Schedule Of Statements Of Cash Flows

STATEMENTS OF CASH FLOWS



	Years Ended December 31,
	2011			2010			2009
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	469,004		$	317,328		$	468,969
CASH FLOWS FROM INVESTING ACTIVITIES:
MEP Transaction	—			3,258			—
Net cash provided by investing activities	—			3,258			—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	91,500			1,858,245			67,505
Principal payments on debt	(20,000		)	(1,632,374		)	(65,816		)
Distributions to partners	(525,596		)	(483,048		)	(470,658		)
Debt issuance costs	(23,695		)	(36,224		)	—
Net cash used in financing activities	(477,791		)	(293,401		)	(468,969		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(8,787		)	27,185			—
CASH AND CASH EQUIVALENTS, beginning of period	27,247			62			62
CASH AND CASH EQUIVALENTS, end of period	$	18,460		$	27,247		$	62

Operations And Organization (Narrative) (Details) - Lone Star L.L.C. [Member]	Dec. 31, 2011	Sep. 30, 2011
Regency [Member]
Subsidiary Interest in Joint Venture	30.00%	30.00%
ETP [Member]
Subsidiary Interest in Joint Venture	70.00%	70.00%

Operations And Organization (Schedule Of Equity Interests (Details)	Dec. 31, 2011 shares
ETP [Member]
General Partner Interest	1.50%
Incentive Distribution Rights	100.00%
Limited Partner Units	50,226,967
Regency [Member]
General Partner Interest	1.80%
Incentive Distribution Rights	100.00%
Limited Partner Units	26,266,791

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accounting Policies [Abstract]
Debt obligations fair value	$ 12,210,000	$ 10,230,000
Debt obligations, carrying amount	11,371,024	9,381,372
Shipping and handling costs	$ 40,400	$ 43,300	$ 55,900
Rate Of Non Qualifying Income Maximum For Income Tax Purpose	10.00%

- Definition

Cost incurred during the reporting period in transporting goods and services to customers. Includes freight-out costs.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 22
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 00-10
-Paragraph 6
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6367646&loc=d3e18780-107790

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6367646&loc=d3e18726-107790

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 605
-SubTopic 45
-Section 45
-Paragraph 20
-URI http://asc.fasb.org/extlink&oid=6743974&loc=d3e60635-111653

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Handling Costs
-URI http://asc.fasb.org/extlink&oid=6514758

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 605
-SubTopic 45
-Section S99
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6408413&loc=d3e221937-122793

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 605
-SubTopic 45
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6408196&loc=d3e61069-111654

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Shipping Costs
-URI http://asc.fasb.org/extlink&oid=6525344

+ Details

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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accounting Policies [Abstract]
Accounts receivable	$ 6,073	$ 92,085	$ 28,431
Accounts receivable from related companies	(23,816)	(26,265)	(26,321)
Inventories	50,991	14,750	(101,592)
Exchanges receivable	620	1,064	22,074
Other current assets	(51,398)	33,233	8,195
Other non-current assets	7,077	5,843	(1,467)
Accounts payable	21,452	(66,936)	(16,024)
Accounts payable to related companies	5,857	(9,939)	4,184
Exchanges payable	1,954	(3,841)	(35,433)
Accrued and other current liabilities	84,704	72,669	(101,927)
Other non-current liabilities	(118)	442	1,401
Price risk management assets and liabilities, net	54,752	146,438	(130,157)
Net change in operating assets and liabilities, net of effects of acquisitions	$ 158,148	$ 259,543	$ (348,636)

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplemental Cash Flow Information [Abstract]
Accrued capital expenditures	$ 225,827	$ 108,076	$ 46,134
Gain from subsidiary common unit transactions	153,039	352,307	96,996
Long-term debt assumed and non-compete agreement notes payable issued from acquisitions	4,166	1,242,604	26,237
Subsidiary issuance of Common Units in connection with certain acquisitions	3,000	584,436	63,339
Cash paid for interest, net of interest capitalized	728,112	547,286	440,492
Cash paid for income taxes	$ 26,603	$ 9,188	$ 15,447

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule of Inventory) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010
Inventory, Net [Abstract]
Natural gas and NGLs, excluding propane		$ 146,132	$ 170,179
Propane		86,958	76,341
Appliances, parts and fittings and other		94,873	119,864
Total inventories		$ 327,963	$ 366,384
Inventory Write-down	$ 54,000
Fair Value Hedge Adjustments related to Inventory	$ 66,100

- Definition

Charge to cost of goods sold that represents the reduction of the carrying amount of inventory, generally attributable to obsolescence or market conditions.

+ References + Details

- Definition

Carrying amount as of the balance sheet date of products used directly or indirectly in the manufacturing or production process, which may or may not become part of the final product. May also include items used in the storage, presentation or transportation of physical goods.

+ References + Details

Estimates, Significant Accounting Policies and Balance Sheet Detail (Other Current Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Other Information [Abstract]
Deposits paid to vendors	$ 66,231	$ 52,192
Prepaid expenses and other	115,673	57,167
Total other current assets	$ 181,904	$ 109,359

Estimates, Significant Accounting Policies and Balance Sheet Detail (Property, Plant and Equipment) (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2011

USD ($)

years

Dec. 31, 2010

USD ($)

Dec. 31, 2009

USD ($)

Property, Plant and Equipment, Net [Abstract]

Impairment of long-lived assets | $

$ 0

Property, plant and equipment, gross | $

16,529,339

13,284,430

Less - Accumulated depreciation | $

(1,970,777)

(1,431,698)

PROPERTY, PLANT AND EQUIPMENT, net | $

14,558,562

11,852,732

Land and improvements [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

137,352

103,325

Buildings and improvements [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 278,829

383,274

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Pipelines and equipment [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 11,358,550

9,709,568

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Natural gas and NGL storage facilities [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

^[1]

$ 789,612

100,909

Property, plant and equipment, useful life, maximum (years)

Bulk storage, equipment and facilities [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 976,882

736,520

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Tanks and other equipment [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 643,527

623,126

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Vehicles [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 230,609

200,702

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Right of way [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 793,232

637,930

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Furniture and fixtures [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 48,466

41,205

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Linepack [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 58,982

55,744

Pad gas [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

57,907

Other [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 234,440

189,103

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Construction work-in-process [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, gross | $

$ 920,951

$ 445,117

LDH [Member]

Property, Plant and Equipment, Net [Abstract]

Business Acquisition, Property, Plant and Equipment | $

^[2]

1,419,591

LDH [Member] | Land and improvements [Member]

Property, Plant and Equipment, Net [Abstract]

Business Acquisition, Property, Plant and Equipment | $

$ 30,759

LDH [Member] | Buildings and improvements [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Business Acquisition, Property, Plant and Equipment | $

$ 3,123

LDH [Member] | Pipelines and equipment [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Business Acquisition, Property, Plant and Equipment | $

$ 662,881

LDH [Member] | Vehicles [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Business Acquisition, Property, Plant and Equipment | $

$ 242

LDH [Member] | Furniture and fixtures [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Business Acquisition, Property, Plant and Equipment | $

$ 49

LDH [Member] | Linepack [Member]

Property, Plant and Equipment, Net [Abstract]

Business Acquisition, Property, Plant and Equipment | $

$ 704

LDH [Member] | Other [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Business Acquisition, Property, Plant and Equipment | $

$ 8,526

LDH [Member] | Construction work-in-process [Member]

Property, Plant and Equipment, Net [Abstract]

Business Acquisition, Property, Plant and Equipment | $

$ 30,888

LDH [Member] | Natural gas liquids storage [Member]

Property, Plant and Equipment, Net [Abstract]

Property, plant and equipment, useful life, maximum (years)

Business Acquisition, Property, Plant and Equipment | $

$ 682,419

[1]

Includes $682.4 million of natural gas liquids storage facilities acquired in connection with the LDH Acquisition described in Note 3.

[2]

Property, plant and equipment (and estimated useful lives) acquired in the LDH Acquisition consisted of the following:Land and improvements$30,759Buildings and improvements (10 to 40 years)3,123Pipelines and equipment (20 to 65 years)662,881Natural gas liquids storage (40 years)682,419Linepack704Vehicles (3 to 20 years)242Furniture and fixtures (3 to 10 years)49Other (5 to 10 years)8,526Construction work-in-process30,888Property, plant and equipment$1,419,591

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Property, Plant and Equipment [Line Items]
Depreciation expense	$ 556,569	$ 394,698	$ 304,129
Capitalized interest, excluding AFUDC	$ 12,630	$ 4,071	$ 11,791

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule Of Goodwill) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Goodwill [Roll Forward]
Goodwill	$ 1,600,611	$ 775,094
Goodwill acquired	438,364	826,249
Other		(732)
Goodwill	2,038,975	1,600,611	$ 775,094
Goodwill, impairment loss	0	0	0
Goodwill, net increase	438,400	825,500
Investment in ETP [Member]
Goodwill [Roll Forward]
Goodwill	781,233	745,505
Goodwill acquired	438,364	36,460
Other		(732)
Goodwill	1,219,597	781,233	745,505
Investment in Regency [Member]
Goodwill [Roll Forward]
Goodwill	789,789	0
Goodwill acquired	0	789,789
Other		0
Goodwill	789,789	789,789	0
Corporate And Other [Member]
Goodwill [Roll Forward]
Goodwill	29,589	29,589
Goodwill acquired	0	0
Other		0
Goodwill	$ 29,589	$ 29,589	$ 29,589

- Definition

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-Subparagraph l
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6905597&loc=d3e13816-109267

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

Loss recognized during the period that results from the write-down of goodwill after comparing the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. Goodwill is assessed at least annually for impairment.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 47
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 20
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 5
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 2
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6905597&loc=d3e13854-109267

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13777-109266

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=6905597&loc=d3e13816-109267

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Estimates, Significant Accounting Policies and Balance Sheet Detail (Components And Useful Lives Of Intangibles And Other Assets) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)
Accumulated Amortization, Intangibles, Gross	$ 148,711	$ 102,991
Gross Carrying Amount	1,141,663	1,060,392
Accumulated Amortization	(148,711)	(102,991)
Gross Carrying Amount, Total intangible assets	1,221,002	1,137,837
Trademarks [Member]
Accumulated Amortization	0	0
Gross Carrying Amount, Non-amortizable intangible assets	79,339	77,445
Customer relationships, contracts and agreements [Member]
Gross Carrying Amount	1,058,662	971,657
Accumulated Amortization	$ (134,909)	(88,583)
Intangible assets, useful life (years) \| years	30
Intangible assets, useful life, minimum (years) \| years	3
Intangible assets, useful life, maximum (years) \| years	46
Trade names [Member]
Gross Carrying Amount	$ 65,500	65,500
Accumulated Amortization	$ (5,185)	(1,910)
Intangible assets, useful life (years) \| years	20
Noncompete agreements [Member]
Gross Carrying Amount	$ 15,431	21,165
Accumulated Amortization	$ (7,835)	(11,888)
Intangible assets, useful life, minimum (years) \| years	3
Intangible assets, useful life, maximum (years) \| years	15
Patents [Member]
Gross Carrying Amount	$ 750	750
Accumulated Amortization	$ (201)	(118)
Intangible assets, useful life (years) \| years	9
Other [Member]
Gross Carrying Amount	$ 1,320	1,320
Accumulated Amortization	$ (581)	$ (492)
Intangible assets, useful life, minimum (years) \| years	10
Intangible assets, useful life, maximum (years) \| years	15

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule Of Finite-Lived Intangible Assets Acquired As Part Of Business Combination) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 years	May 31, 2010 USD ($)
Business Acquisition [Line Items]
Intangible assets \| $		$ 666,360
Customer Contracts [Member]
Business Acquisition [Line Items]
Intangible assets, useful life, minimum (years)	3
Intangible assets, useful life, maximum (years)	15
Customer Relationships, Contracts And Agreements [Member]
Business Acquisition [Line Items]
Intangible assets \| $		600,860
Intangible assets, useful life (years)	30
Intangible assets, useful life, minimum (years)	3
Intangible assets, useful life, maximum (years)	46
Trade Names [Member]
Business Acquisition [Line Items]
Intangible assets \| $		$ 65,500
Intangible assets, useful life (years)	20

Estimates, Significant Accounting Policies and Balance Sheet Detail (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Depreciation And Amortization [Member]
Reported in depreciation and amortization	$ 54,655	$ 35,602	$ 20,895

Estimates, Significant Accounting Policies and Balance Sheet Detail (Estimated Aggregate Amortization Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Goodwill and Intangible Assets Disclosure [Abstract]
2012	$ 44,793
2013	40,871
2014	39,746
2015	39,746
2016	39,746
Impairment of intangible assets	0	$ 0	$ 0
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	1,141,663	$ 1,060,392
ETP's Propane Operations [Member] \| Sale [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	$ 127,700

Estimates, Significant Accounting Policies and Balance Sheet Detail (Schedule of Other Non-Current Assets, net) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)
Unamortized financing costs	$ 132,375	$ 98,067
Regulatory assets	88,993	92,939
Other	27,542	34,575
Total other non-current assets, net	$ 248,910	$ 225,581
Financing Costs [Member]
Finite-Lived Intangible Assets, Useful Life, Maximum \| years	30
Finite-Lived Intangible Assets, Useful Life, Minimum \| years	3

Estimates, Significant Accounting Policies and Balance Sheet Detail (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Other Information [Abstract]
Interest payable	$ 204,182	$ 191,466
Customer advances and deposits	100,525	111,448
Accrued capital expenditures	228,877	87,260
Accrued wages and benefits	80,205	76,592
Taxes payable other than income taxes	79,331	36,204
Income taxes payable	14,781	8,344
Other	56,011	56,374
Total accrued and other current liabilities	$ 763,912	$ 567,688

- Definition

Carrying value as of the balance sheet date of obligations incurred and payable for real and property taxes. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

+ References + Details

- Definition

Carrying value as of the balance sheet date of obligations, excluding pension and other postretirement benefits, incurred through that date and payable for perquisites provided to employees pertaining to services received from them. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

+ References + Details

- Definition

Carrying value as of the balance sheet date of [accrued] interest payable on all forms of debt, including trade payables, that has been incurred and is unpaid. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

+ References + Details

- Definition

Aggregate carrying amount, as of the balance sheet date, of obligations incurred and payable, pertaining to costs that are statutory in nature, are incurred on contractual obligations, or accumulate over time and for which invoices have not yet been received or will not be rendered and of liabilities not separately disclosed in the balance sheet. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

+ References + Details

Estimates, Significant Accounting Policies and Balance Sheet Detail (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Marketable securities, Asset Fair Value	$ 1,229	$ 2,032
Series A Convertible Preferred Units, Liability Fair Value	(322,910)	(317,600)
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	361,959
Fair Value, Measurements, Recurring [Member]
Marketable securities, Asset Fair Value	1,229	2,032
Interest rate derivatives, Asset Fair Value	36,301	20,790
Commodity derivatives, Asset Fair Value	304,489	95,765
Total Assets	342,019	118,587
Interest rate derivatives, Liability Fair Value	(117,490)	(20,922)
Series A Convertible Preferred Units, Liability Fair Value	(322,910)	(317,600)
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	(39,049)	(57,023)
Commodity derivatives, Liability Fair Value	(261,458)	(80,307)
Total Liabilities	(740,907)	(475,852)
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member]
Marketable securities, Asset Fair Value	1,229	2,032
Interest rate derivatives, Asset Fair Value	0	0
Commodity derivatives, Asset Fair Value	279,183	59,792
Total Assets	280,412	61,824
Interest rate derivatives, Liability Fair Value	0	0
Series A Convertible Preferred Units, Liability Fair Value	0	0
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	0	0
Commodity derivatives, Liability Fair Value	(233,462)	(62,717)
Total Liabilities	(233,462)	(62,717)
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member]
Marketable securities, Asset Fair Value	0	0
Interest rate derivatives, Asset Fair Value	36,301	20,790
Commodity derivatives, Asset Fair Value	25,306	35,973
Total Assets	61,607	56,763
Interest rate derivatives, Liability Fair Value	(117,490)	(20,922)
Series A Convertible Preferred Units, Liability Fair Value	0	0
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	0	0
Commodity derivatives, Liability Fair Value	(27,996)	(17,590)
Total Liabilities	(145,486)	(38,512)
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member]
Marketable securities, Asset Fair Value	0	0
Interest rate derivatives, Asset Fair Value	0	0
Commodity derivatives, Asset Fair Value	0	0
Total Assets	0	0
Interest rate derivatives, Liability Fair Value	0	0
Series A Convertible Preferred Units, Liability Fair Value	(322,910)	(317,600)
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	(39,049)	(57,023)
Commodity derivatives, Liability Fair Value	0	0
Total Liabilities	(361,959)
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		374,623
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Condensate - Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	538
Commodity derivatives, Liability Fair Value	(1,567)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Basis Swaps IFERC/NYMEX [Member]
Commodity derivatives, Asset Fair Value	62,924	15,756
Commodity derivatives, Liability Fair Value	(82,290)	(17,372)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives, Asset Fair Value	15,002	1,682
Commodity derivatives, Liability Fair Value	(16,074)	(3,768)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	218,479	44,955
Commodity derivatives, Liability Fair Value	(148,111)	(42,252)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Options - Puts [Member]
Commodity derivatives, Asset Fair Value	6,435	26,241
Commodity derivatives, Liability Fair Value		(7)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Options - Calls [Member]
Commodity derivatives, Asset Fair Value		75
Commodity derivatives, Liability Fair Value	(12)	(2,643)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Forward Physical Swaps [Member]
Commodity derivatives, Asset Fair Value	699
Commodity derivatives, Liability Fair Value	(712)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| NGLs - Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	94	192
Commodity derivatives, Liability Fair Value	(8,561)	(10,684)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| NGLs Options - Puts [Member]
Commodity derivatives, Asset Fair Value	309
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Propane Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	9	6,864
Commodity derivatives, Liability Fair Value	(4,131)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| WTI Crude Oil [Member]
Commodity derivatives, Liability Fair Value		(3,581)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| Condensate - Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0
Commodity derivatives, Liability Fair Value	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| Basis Swaps IFERC/NYMEX [Member]
Commodity derivatives, Asset Fair Value	62,924	15,756
Commodity derivatives, Liability Fair Value	(82,290)	(17,372)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives, Asset Fair Value	1,687	1,562
Commodity derivatives, Liability Fair Value	(3,061)	(3,520)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	214,572	42,474
Commodity derivatives, Liability Fair Value	(148,111)	(41,825)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| Options - Puts [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| Options - Calls [Member]
Commodity derivatives, Asset Fair Value		0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| Forward Physical Swaps [Member]
Commodity derivatives, Asset Fair Value	0
Commodity derivatives, Liability Fair Value	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| NGLs - Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| NGLs Options - Puts [Member]
Commodity derivatives, Asset Fair Value	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| Propane Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 1 [Member] \| WTI Crude Oil [Member]
Commodity derivatives, Liability Fair Value		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| Condensate - Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	538
Commodity derivatives, Liability Fair Value	(1,567)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| Basis Swaps IFERC/NYMEX [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives, Asset Fair Value	13,315	120
Commodity derivatives, Liability Fair Value	(13,013)	(248)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	3,907	2,481
Commodity derivatives, Liability Fair Value	0	(427)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| Options - Puts [Member]
Commodity derivatives, Asset Fair Value	6,435	26,241
Commodity derivatives, Liability Fair Value		(7)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| Options - Calls [Member]
Commodity derivatives, Asset Fair Value		75
Commodity derivatives, Liability Fair Value	(12)	(2,643)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| Forward Physical Swaps [Member]
Commodity derivatives, Asset Fair Value	699
Commodity derivatives, Liability Fair Value	(712)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| NGLs - Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	94	192
Commodity derivatives, Liability Fair Value	(8,561)	(10,684)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| NGLs Options - Puts [Member]
Commodity derivatives, Asset Fair Value	309
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| Propane Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	9	6,864
Commodity derivatives, Liability Fair Value	(4,131)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 2 [Member] \| WTI Crude Oil [Member]
Commodity derivatives, Liability Fair Value		(3,581)
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| Condensate - Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0
Commodity derivatives, Liability Fair Value	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| Basis Swaps IFERC/NYMEX [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| Options - Puts [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value		0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| Options - Calls [Member]
Commodity derivatives, Asset Fair Value		0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| Forward Physical Swaps [Member]
Commodity derivatives, Asset Fair Value	0
Commodity derivatives, Liability Fair Value	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| NGLs - Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| NGLs Options - Puts [Member]
Commodity derivatives, Asset Fair Value	0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| Propane Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	$ 0
Fair Value, Measurements, Recurring [Member] \| Commodity Derivatives [Member] \| Level 3 [Member] \| WTI Crude Oil [Member]
Commodity derivatives, Liability Fair Value		$ 0

Estimates, Significant Accounting Policies and Balance Sheet Detail (Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net unrealized gains included in other income (expense)	$ 12,664
Ending Balance	(361,959)
Impairment of investments in affiliates	$ 5,355	$ 52,620	$ 0
ETP [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Impairment of investments in affiliates		$ 52,600

- Definition

The amount by which the fair value of an investment is less than the amortized cost basis or carrying amount of that investment at the balance sheet date and the decline in fair value is deemed to be other than temporary, before considering whether or not such amount is recognized in earnings or other comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 115
-Paragraph 16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 320
-SubTopic 10
-Section 35
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6956420&loc=d3e25351-111560

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS115-1/124-1
-Paragraph 15C
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS115-1/124-1
-Paragraph 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS115-1/124-1
-Paragraph 16B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS115-2/124-2
-Paragraph 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Estimates, Significant Accounting Policies and Balance Sheet Detail (Components Of Federal And State Income Tax) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current expense (benefit):
Federal	$ (842)	$ 1,602	$ (8,850)
State	16,883	8,594	9,657
Total current expense (benefit)	16,041	10,196	807
Deferred expense (benefit):
Federal	416	2,788	8,643
State	426	754	(221)
Total deferred expense (benefit)	842	3,542	8,422
Total income tax expense	16,883	13,738	$ 9,229
Deferred tax liabilities, noncurrent	217,200	213,900
Deferred tax liabilities, property, plant and equipment	146,600	143,900
Deferred tax liabilities, basis difference associated with ETP's Class E units	72,200	70,200
Deferred tax liabilities, current	$ 100	$ 400

Acquisitions and Related Transactions (Narrative) (Details)			1 Months Ended						12 Months Ended
	Jan. 12, 2012 USD ($) shares	May 27, 2010 shares	Feb. 29, 2012 USD ($)	Oct. 31, 2011 quarters	Sep. 30, 2011 USD ($)	Jul. 31, 2011 USD ($)	Mar. 31, 2010 USD ($) mile	Nov. 30, 2009 shares	Dec. 31, 2011 USD ($) shares	Sep. 30, 2010 USD ($)	May 31, 2010 USD ($)	May 25, 2010 USD ($) shares	Aug. 31, 2009 USD ($)	Aug. 01, 2009 USD ($)
Cash paid in Acquisition									$ 1,980,000,000
Consideration of Acquisition												$ 305,000,000
Preferred units liquidation preference									$ 300,000,000
Business acquisition intangible assets recorded, value											$ 666,360,000
Regency [Member]
Business Acquisition Units Acquired \| shares												26,300,000
ETP [Member]
Stock Redeemed or Called During Period, Shares \| shares		12,300,000
ETP [Member] \| Sale [Member]
Business Acquisition Units Acquired \| shares	29,600,000
Contingent Residual Support Agreement Obligation	$ 1,500,000,000
Debt Of Subsidiary Guaranteed	1,500,000,000
ETP's Propane Operations [Member] \| Sale [Member]
Consideration of Acquisition	1,460,000,000
Part Noncash Divestiture, Amount of Noncash Consideration Received	$ 71,000,000
Lone Star L.L.C. [Member] \| Regency [Member]
Subsidiary Interest in Joint Venture					30.00%				30.00%
Consideration of Acquisition									$ 592,700,000
Lone Star L.L.C. [Member] \| ETP [Member]
Subsidiary Interest in Joint Venture					70.00%				70.00%
Consideration of Acquisition									$ 1,380,000,000
MEP [Member] \| Regency [Member]
Interest ownership												49.90%
Equity method investment, acquire additional ownership percentage		0.10%
SUG Merger [Member]
Acquisition of all outstanding shares of SUG, total transaction price									9,400,000,000
Proposed Business Combination, Cash Paid and Equity Issued									5,700,000,000
Amount of SUG debt assumed as part of acquisition price									3,700,000,000
Cash paid in exchange of each share									$ 44.25
Number of share received in exchange of each share \| shares									1.00
Percentage of maximum cash consideration in total consideration									60.00%
SUG Merger [Member] \| Minimum [Member]
Percentage of fluctuation in common unit									40.00%
SUG Merger [Member] \| Maximum [Member]
Percentage of fluctuation in common unit									50.00%
Citrus Transaction [Member] \| ETP [Member]
Incentive distributions to relinquish									$ 220,000,000
Incentive distributions to be forfeited periods \| quarters				16
Citrus Transaction [Member] \| Citrus Corp [Member]
Equity method investment ownership percentage of pending acquisition									50.00%
Potential business acquisition cash payment									$ 1,900,000,000
Common units received due to business exchange									105,000,000
Purchase price									$ 2,000,000,000
Citrus Transaction [Member] \| Florida Gas Transmission Pipeline System [Member]
Percentage ownership operating facility									100.00%
Regency [Member]
Acquisition of all outstanding shares of SUG, total transaction price												$ 304,950,000
Business Acquisition, Purchase Price Allocation, Goodwill Amount												789,789,000
Business acquisition intangible assets recorded, value												666,360,000
Liabilities assumed in connection with business acquisition, amount												$ 3,665,942,000
Regency [Member] \| ETE Preferred Units [Member]
Temporary Equity, Shares Issued \| shares												3,000,000
Preferred units liquidation preference												$ 300,000,000
Zephyr [Member] \| Regency [Member]
Consideration of Acquisition										$ 193,300,000
Business Acquisition, Purchase Price Allocation, Goodwill Amount										0
Business acquisition intangible assets recorded, value										$ 119,400,000
Other Acquisiitons [Member] \| ETP [Member]
Length of pipeline acquired \| mile							120
Consideration of Acquisition							$ 150,000,000
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned														$ 63,300,000
Customer contracts recorded in connection with business acquisition, amount							68,200,000
Business Acquisition, Purchase Price Allocation, Goodwill Amount							$ 27,300,000						$ 1,700,000	8,700,000
Stock issued for business acquisition, units \| shares								1,450,076
Cash Acquired from Acquisition					$ 41,100,000
Liabilities assumed in connection with business acquisition, amount													$ 33,500,000	30,500,000
Notes payable assumed in connection with business acquisition, amount														$ 8,400,000
East Texas Gathering And Processing Assets [Member] \| Regency [Member]
Cash received from sale of assets						$ 70,200,000
Bridge Loan [Member] \| SUG Merger [Member]
Aggregate principal amount									$ 3,700,000,000
Bridge Loan [Member] \| SUG Merger [Member] \| Financing [Member]
Aggregate principal amount									3,700,000,000
Extinguishment of Debt, Amount			$ 3,700,000,000
ETE Senior Secured Revolving Credit Facilities [Member] \| Revolving Credit Facility [Member]
Revolving credit facility									200,000,000
Extinguishment of Debt, Amount									$ 500,000,000
ETE Senior Secured Revolving Credit Facilities [Member] \| Revolving Credit Facility [Member] \| Financing [Member]
Revolving credit facility			$ 2,300,000,000

Acquisitions and Related Transactions (Schedule of Components Of Property, Plant And Equipment Acquired) (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2011

USD ($)

years

Buildings and improvements [Member]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Pipelines and equipment [Member]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Vehicles [Member]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Furniture and fixtures [Member]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

Other [Member]

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

LDH [Member]

Property, plant, and equipment | $

$ 1,419,591

^[1]

LDH [Member] | Land and improvements [Member]

Property, plant, and equipment | $

30,759

LDH [Member] | Buildings and improvements [Member]

Property, plant, and equipment | $

$ 3,123

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

LDH [Member] | Pipelines and equipment [Member]

Property, plant, and equipment | $

$ 662,881

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

LDH [Member] | Natural gas liquids storage [Member]

Property, plant, and equipment | $

$ 682,419

Property, plant and equipment, useful life, maximum (years)

LDH [Member] | Linepack [Member]

Property, plant, and equipment | $

$ 704

LDH [Member] | Vehicles [Member]

Property, plant, and equipment | $

$ 242

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

LDH [Member] | Furniture and fixtures [Member]

Property, plant, and equipment | $

$ 49

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

LDH [Member] | Other [Member]

Property, plant, and equipment | $

$ 8,526

Property, plant and equipment, useful life, maximum (years)

Property, plant and equipment, useful life, minimum (years)

LDH [Member] | Construction work-in-process [Member]

Property, plant, and equipment | $

$ 30,888

[1]

Acquisitions and Related Transactions (Pro Forma Results Of Operations) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Acquisitions and Dispositions [Abstract]
Revenues	$ 8,349,292	$ 7,406,943
Net income	520,034	347,572
Net income attributable to partners	$ 307,809	$ 228,206
Basic net income per Limited Partner unit	$ 1.38	$ 1.02
Diluted net income per Limited Partner unit	$ 1.38	$ 1.02

- Definition

The pro forma basic net income per share for a period as if the business combination or combinations had been completed at the beginning of a period.

+ References + Details

- Definition

The pro forma diluted net income per share for a period as if the business combination or combinations had been completed at the beginning of a period.

+ References + Details

Acquisitions and Related Transactions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition) (Details) - USD ($)
$ in Thousands

Dec. 31, 2011

Dec. 31, 2010

May 31, 2010

May 25, 2010

Business Acquisition [Line Items]

Convertible Preferred Units

$ 322,910

$ 317,600

Intangible assets

$ 666,360

Regency [Member]

Business Acquisition [Line Items]

Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt

$ 1,239,863

Convertible Preferred Units

70,793

Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value

2,104,981

Total current assets

189,502

Property, plant, and equipment

1,548,384

Investments in and Advances to Affiliates, at Fair Value

739,164

789,789

666,360

37,693

3,970,892

Total current liabilities

192,788

Other long-term liabilities

57,517

Total liabilities

3,665,942

Total consideration

304,950

Cash received

23,995

Total consideration, net of cash received

$ 280,955

LDH [Member]

Business Acquisition [Line Items]

Total current assets

118,177

Property, plant, and equipment

^[1]

1,419,591

432,026

81,000

157

2,050,951

Total current liabilities

74,964

Other long-term liabilities

438

Total liabilities

75,402

Total consideration

1,975,549

Cash received

31,231

Total consideration, net of cash received

$ 1,944,318

[1]

Investment in Affiliates (Details) $ in Thousands		1 Months Ended	12 Months Ended
Investment in Affiliates (Details) $ in Thousands	May 27, 2010	Sep. 30, 2011 USD ($)	Dec. 31, 2011 USD ($) mile	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 02, 2011 MMcf	May 25, 2010
Impairment of investments in affiliates \| $			$ 5,355	$ 52,620	$ 0
ETP [Member]
Impairment of investments in affiliates \| $				$ 52,600
MEP [Member]
Length Of Pipeline \| mile			500
RIGS Haynesville Partnership Co. [Member]
Interest ownership			49.99%
Length Of Pipeline \| mile			450
Fayetteville Express Pipeline, LLC [Member]
Length Of Pipeline \| mile			185
Ranch JV [Member]
Subsidiary Interest in Joint Venture						33.33%
MEP [Member] \| Regency [Member]
Interest ownership							49.90%
Equity method investment, acquire additional ownership percentage	0.10%
Equity method investment, additional ownership percentage acquired, exercise of option		0.10%
Payments to acquire interest in affiliates \| $		$ 1,200
Refrigeration Plant [Member]
Amount of natural gas processed daily \| MMcf						25
Cryogenic Processing Plant [Member]
Amount of natural gas processed daily \| MMcf						100

Investments in Affiliates (Schedule Of Aggregated Balance Sheet Information Of Unconsolidated Affiliates) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Investment In Affiliates [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets	$ 88,583	$ 83,735
Property, plant and equipment, net	3,987,460	4,052,396
Other assets	152,904	160,655
Total assets	4,228,947	4,296,786
Current Liabilities	83,989	91,860
Non-current liabilities	1,478,499	1,772,686
Equity	2,666,459	2,432,240
Total liabilities and equity	$ 4,228,947	$ 4,296,786

- Definition

The amount of assets reported by an equity method investment of the entity.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph bb
-Article 1

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph w
-Article 1

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 4
-Section 08
-Paragraph g
-Subparagraph 1, 2

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(g))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33918-111571

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33912-111571

+ Details

- Definition

The amount of current assets reported by an equity method investment of the entity.

+ References

+ Details

- Definition

The amount of current liabilities reported by an equity method investment of the entity.

+ References

+ Details

- Definition

The amount of liabilities and equity reported by an equity method investment of the entity.

+ References

+ Details

- Definition

The amount of noncurrent liabilities reported by an equity method investment of the entity.

+ References

+ Details

Investments In Affiliates (Pro Forma Results Of Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Investment In Affiliates [Abstract]
Revenues	$ 569,116	$ 406,346	$ 142,076
Operating Income	324,686	221,623	66,333
Net income	$ 242,316	$ 166,910	$ 56,247

- Definition

The amount of net income (loss) reported by an equity method investment of the entity.

+ References

+ Details

Net Income Per Limited Partner Unit (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011 USD ($) $ / shares	Sep. 30, 2011 USD ($) $ / shares	Jun. 30, 2011 USD ($) $ / shares	Mar. 31, 2011 USD ($) $ / shares	Dec. 31, 2010 USD ($) $ / shares	Sep. 30, 2010 USD ($) $ / shares	Jun. 30, 2010 USD ($) $ / shares	Mar. 31, 2010 USD ($) $ / shares	Dec. 31, 2011 USD ($) $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares shares
Net Income (Loss) Allocated to Limited Partners	$ 85,537	$ 68,869	$ 66,080	$ 88,366	$ 75,814	$ (15,289)	$ 19,208	$ 112,428	$ 308,852	$ 192,161	$ 441,103
Weighted average Limited Partner units \| shares									222,968,261	222,941,156	222,898,203
Limited Partners' interest in net income (loss) \| $ / shares	0.38	0.31	0.30	0.40	0.34	(0.07)	0.09	0.50	1.39	0.86	1.98
Dilutive effect of equity-based compensation of subsidiaries									$ (620)	$ (228)	$ (410)
Weighted average Limited Partner units \| shares									222,968,261	222,941,156	222,898,203
Diluted net income (loss) per Limited Partner unit \| $ / shares	0.38	0.31	0.30	0.40	0.34	(0.07)	0.09	0.50	1.38	0.86	1.98
Discontinued operations impact per Limited Partner unit, omitted \| $ / shares									0.00	0.00	0.00
Preferred units liquidation preference	$ 300,000								$ 300,000
Earnings Per Share, Basic [Member]
Net Income (Loss) Allocated to Limited Partners									308,852	$ 192,161	$ 441,103
Earnings Per Share, Diluted [Member]
Diluted net income (loss) available to Limited Partners									$ 308,232	$ 191,933	$ 440,693

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Oct. 31, 2010
Debt Instrument [Line Items]
Other Long-term Debt	$ 10,434	$ 9,671
Debt Instrument, Unamortized Discount (Premium), Net	(10,309)	(6,013)
Fair Value Adjustment Related To Interest Rate Swaps	11,647	17,260
Long-term Debt	11,371,024	9,381,372
Current maturities of long-term debt	(424,160)	(35,305)
LONG-TERM DEBT, less current maturities	$ 10,946,864	9,346,067
Regency Senior Notes [Member] \| 9.375% Senior Notes due June 1,2016 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	9.375%
Regency Senior Notes [Member] \| 6.875% Senior Notes due December 1, 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			6.875%
Parent Company [Member]
Debt Instrument [Line Items]
LONG-TERM DEBT, less current maturities	$ 1,871,500	1,800,000
Parent Company [Member] \| ETE Senior Notes, due October 15, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes	1,800,000	1,800,000
Parent Company [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Debt Instrument [Line Items]
Outstanding borrowings	71,500	0
ETP [Member] \| Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Outstanding borrowings	314,400	402,327
ETP [Member] \| 5.65% Senior Notes due August 1, 2012 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 400,000	$ 400,000
Debt instrument, interest rate, stated percentage	5.65%	5.65%
ETP [Member] \| 6.0% Senior Notes due July 1, 2013 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 350,000	$ 350,000
Debt instrument, interest rate, stated percentage	6.00%	6.00%
ETP [Member] \| 8.5% Senior Notes due April 15, 2014 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 350,000	$ 350,000
Debt instrument, interest rate, stated percentage	8.50%	8.50%
ETP [Member] \| 5.95% Senior Notes due February 1, 2015 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 750,000	$ 750,000
Debt instrument, interest rate, stated percentage	5.95%	5.95%
ETP [Member] \| 6.125% Senior Notes due February 15, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 400,000	$ 400,000
Debt instrument, interest rate, stated percentage	6.125%	6.125%
ETP [Member] \| 6.7% Senior Notes due July 1, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 600,000	$ 600,000
Debt instrument, interest rate, stated percentage	6.70%	6.70%
ETP [Member] \| 9.7% Senior Notes due March 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 600,000	$ 600,000
Debt instrument, interest rate, stated percentage	9.70%	9.70%
ETP [Member] \| 9.0% Senior Notes due April 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 650,000	$ 650,000
Debt instrument, interest rate, stated percentage	9.00%	9.00%
ETP [Member] \| 4.65% Senior Notes due June 1, 2021 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 800,000	$ 0
Debt instrument, interest rate, stated percentage	4.65%	4.65%
ETP [Member] \| 6.625% Senior Notes due October 15, 2036 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 400,000	$ 400,000
Debt instrument, interest rate, stated percentage	6.625%	6.625%
ETP [Member] \| 7.5% Senior Notes due July 1, 2038 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 550,000	$ 550,000
Debt instrument, interest rate, stated percentage	7.50%	7.50%
ETP [Member] \| 6.05% Senior Notes due June 1, 2041 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 700,000	$ 0
Debt instrument, interest rate, stated percentage	6.05%	6.05%
Regency [Member] \| Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Outstanding borrowings	$ 332,000	$ 285,000
Regency [Member] \| 9.375% Senior Notes due June 1,2016 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 250,000	$ 250,000
Debt instrument, interest rate, stated percentage	9.375%	9.375%
Regency [Member] \| 6.875% Senior Notes due December 1, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 600,000	$ 600,000
Debt instrument, interest rate, stated percentage	6.875%	6.875%
Regency [Member] \| 6.5% Senior Notes due July 15, 2021[Member]
Debt Instrument [Line Items]
Senior Notes	$ 500,000	$ 0
Debt instrument, interest rate, stated percentage	6.50%	6.50%
Transwestern [Member] \| Unsecured Debt [Member] \| 5.39% Senior Notes due November 17, 2014 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 88,000	$ 88,000
Debt instrument, interest rate, stated percentage	5.39%	5.39%
Transwestern [Member] \| Unsecured Debt [Member] \| 5.54% Senior Notes due November 17, 2016 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 125,000	$ 125,000
Debt instrument, interest rate, stated percentage	5.54%	5.54%
Transwestern [Member] \| Unsecured Debt [Member] \| 5.64% Senior Notes due May 24, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 82,000	$ 82,000
Debt instrument, interest rate, stated percentage	5.64%	5.64%
Transwestern [Member] \| Unsecured Debt [Member] \| 5.36% Senior Notes due December 9, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 175,000	$ 175,000
Debt instrument, interest rate, stated percentage	5.36%	5.36%
Transwestern [Member] \| Unsecured Debt [Member] \| 5.89% Senior Notes due May 24, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 150,000	$ 150,000
Debt instrument, interest rate, stated percentage	5.89%	5.89%
Transwestern [Member] \| Unsecured Debt [Member] \| 5.66% Senior Notes due December 9, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 175,000	$ 175,000
Debt instrument, interest rate, stated percentage	5.66%	5.66%
Transwestern [Member] \| Unsecured Debt [Member] \| 6.16% Senior Notes due May 24, 2037 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 75,000	$ 75,000
Debt instrument, interest rate, stated percentage	6.16%	6.16%
HOLP [Member] \| Secured Debt [Member]
Debt Instrument [Line Items]
Senior Notes	$ 71,314	$ 103,127
HOLP [Member] \| Maximum [Member] \| Secured Debt [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	8.87%	8.87%
HOLP [Member] \| Minimum [Member] \| Secured Debt [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	7.26%	7.26%

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Long-term Debt, by Maturity [Abstract]
Total	$ 11,371,024	$ 9,381,372
Unamortized Discounts And Fair Value Adjustments	1,300
Fair Value Adjustment Related To Interest Rate Swaps	11,647	$ 17,260
Consolidated Total (excluding propane business) [Member]
Long-term Debt, by Maturity [Abstract]
2012	400,043
2013	350,046
2014	770,000
2015	821,500
2016	689,438
Thereafter	8,257,000
Total	$ 11,288,027

Debt Obligations (Senior Notes) (Narrative) (Details) $ in Millions	1 Months Ended		9 Months Ended	12 Months Ended
	Jan. 31, 2012 USD ($)	Sep. 30, 2010 USD ($)	Sep. 30, 2011 USD ($)	Dec. 31, 2011 USD ($) days	Jan. 19, 2012 USD ($)	Oct. 31, 2010 USD ($)
HOLP Senior Secured Notes [Member]
One time principal payment on senior secured notes, due 2013				$ 16.0
7.5% Senior Notes Due October 15, 2020 [Member] \| ETE Senior Notes [Member]
Aggregate principal amount of senior notes		$ 1,800.0
Proceeds from debt net of issuance costs		$ 1,770.0
Debt instrument, interest rate, stated percentage		7.50%
4.65% Senior Notes Due June 1, 2021 [Member] \| ETP Senior Notes [Member]
Aggregate principal amount of senior notes			$ 800.0
Debt instrument, interest rate, stated percentage			4.65%
Debt instrument, maturity date			Jun. 01, 2021
6.05% Senior Notes Due June 1, 2041 [Member] \| ETP Senior Notes [Member]
Aggregate principal amount of senior notes			$ 700.0
Debt instrument, interest rate, stated percentage			6.05%
Debt instrument, maturity date			Jun. 01, 2041
6.5% Senior Notes Due July 15, 2021 [Member] \| Regency Senior Notes [Member]
Aggregate principal amount of senior notes				500.0
Proceeds from debt net of issuance costs				491.3
Issuance costs capitalized				$ 9.8
Debt instrument, interest rate, stated percentage				6.50%
Debt instrument, maturity date				Jul. 15, 2021
ETP Credit Facility [Member] \| ETP Senior Notes [Member]
Proceeds from debt net of issuance costs			$ 1,480.0
9.375% Senior Notes due June 1,2016 [Member] \| Regency Senior Notes [Member]
Aggregate principal amount of senior notes				$ 250.0
Debt instrument, interest rate, stated percentage				9.375%
6.875% Senior Notes due December 1, 2018 [Member] \| Regency Senior Notes [Member]
Aggregate principal amount of senior notes						$ 600.0
Debt instrument, interest rate, stated percentage						6.875%
Unamortized debt issuance expense						$ 12.2
Redemption Before June 1, 2012 [Member] \| 9.375% Senior Notes due June 1,2016 [Member] \| Regency Senior Notes [Member]
Offering price for debt redemption, percentage				109.375%
Portion of debt redeemable with equity offering proceeds				35.00%
Redemption Before June 1, 2013 [Member] \| 9.375% Senior Notes due June 1,2016 [Member] \| Regency Senior Notes [Member]
Offering price for debt redemption, percentage				100.00%
Premium Percentage Applied To Principal Due To Debt Redemption				1.00%
Spread on variable rate utilized in determining premium due to debt redemption				0.50%
Redemption Before December 1, 2013 [Member] \| 6.875% Senior Notes due December 1, 2018 [Member] \| Regency Senior Notes [Member]
Offering price for debt redemption, percentage				106.875%
Portion of debt redeemable with equity offering proceeds				35.00%
Redemption Before December 1 2014 [Member] \| 6.875% Senior Notes due December 1, 2018 [Member] \| Regency Senior Notes [Member]
Offering price for debt redemption, percentage				100.00%
Premium Percentage Applied To Principal Due To Debt Redemption				1.00%
Spread on variable rate utilized in determining premium due to debt redemption				0.50%
Redemption Before July 15, 2016 [Member] \| Regency 2021 Notes [Member] \| Regency Senior Notes [Member]
Optional purchase price for debt, percentage				100.00%
Redemption Before July 15, 2014 [Member] \| Regency 2021 Notes [Member] \| Regency Senior Notes [Member]
Offering price for debt redemption, percentage				106.50%
Portion of debt redeemable with equity offering proceeds				35.00%
In The Event Of Change Of Control With Rating Decline [Member] \| Regency 2021 Notes [Member] \| Regency Senior Notes [Member]
Optional purchase price for debt, percentage				101.00%
Number of days within which rating decline must occur \| days				90
Issuance of Debt [Member] \| Senior Notes 6.50% Due Feb 1, 2042 and 5.20% Due Feb 1, 2022 [Member] \| ETP Senior Notes [Member]
Proceeds from debt net of issuance costs	$ 1,980.0
Issuance of Debt [Member] \| 5.20% Senior Notes Due Feb 1, 2022 [Member] \| ETP Senior Notes [Member]
Aggregate principal amount of senior notes	$ 1,000.0
Debt instrument, interest rate, stated percentage	5.20%
Issuance of Debt [Member] \| 6.50% Senior Notes Due Feb 1, 2042 [Member] \| ETP Senior Notes [Member]
Aggregate principal amount of senior notes	$ 1,000.0
Debt instrument, interest rate, stated percentage	6.50%
Issuance of Debt [Member] \| Citrus Merger Agrement Not Completed By April 17 2012 [Member] \| Senior Notes 6.50% Due Feb 1, 2042 and 5.20% Due Feb 1, 2022 [Member] \| ETP Senior Notes [Member]
Extinguishment of Debt, Amount	$ 2,000.0
Offering price for debt redemption, percentage	101.00%
Maximum [Member] \| Tender Offer [Member]
Aggregate Principal Amount Cash Tender Offer	$ 750.0
Any And All Offer [Member] \| Tender Offer [Member] \| 5.65% Senior Notes due August 1, 2012 [Member]
Aggregate Principal Amount Cash Tender Offer					$ 292.0
Maximum Tender Offer [Member] \| Tender Offer [Member] \| 9.7% Senior Notes due March 15, 2019 [Member]
Aggregate Principal Amount Cash Tender Offer					200.0
Maximum Tender Offer [Member] \| Tender Offer [Member] \| 9.0% Senior Notes due April 15, 2019 [Member]
Aggregate Principal Amount Cash Tender Offer					200.0
Maximum Tender Offer [Member] \| Tender Offer [Member] \| 8.5% Senior Notes due April 15, 2014 [Member]
Aggregate Principal Amount Cash Tender Offer					$ 58.1

Debt Obligations (Parent Company Credit Agreement) (Narrative) (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Feb. 29, 2012 USD ($)	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)
ETE Senior Secured Revolving Credit Facilities [Member] \| Parent Company [Member]
Outstanding borrowings		$ 71,500	$ 0
Amount available for future borrowings		$ 128,500
Weighted average interest rate on amount outstanding		3.46%
Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Extinguishment of Debt, Amount		$ 500,000
Revolving credit facility		$ 200,000
Term of revolving credit faciltiy \| years		5
Federal Funds Effective Rate [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Debt instrument, basis spread on variable rate		0.50%
Minimum [Member] \| Eurodollar Loans [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Debt instrument, basis spread on variable rate		2.75%
Minimum [Member] \| Base Rate Loans [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Debt instrument, basis spread on variable rate		1.75%
Minimum [Member] \| Federal Funds Effective Rate [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Line of credit facility, unused capacity, commitment fee percentage		0.50%
Maximum [Member] \| Eurodollar Loans [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Debt instrument, basis spread on variable rate		3.75%
Maximum [Member] \| Base Rate Loans [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Debt instrument, basis spread on variable rate		2.75%
Maximum [Member] \| Federal Funds Effective Rate [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Line of credit facility, unused capacity, commitment fee percentage		0.75%
Financing [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Revolving credit facility	$ 2,300,000
SUG Merger [Member] \| Bridge Loan [Member]
Aggregate principal amount		$ 3,700,000
SUG Merger [Member] \| Financing [Member] \| Bridge Loan [Member]
Extinguishment of Debt, Amount	$ 3,700,000
Aggregate principal amount		$ 3,700,000

Debt Obligations (ETP Credit Facility) (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
ETE Senior Secured Revolving Credit Facilities [Member] \| Parent Company [Member]
Amount Outstanding	$ 71,500	$ 0
Amount available for future borrowings	$ 128,500
Weighted average interest rate on amount outstanding	3.46%
ETP Credit Facility [Member]
Revolving credit facility	$ 2,500,000
Line of credit facility updated borrowing capacity subject to lender approval	3,750,000
Amount available for future borrowings	$ 2,160,000
Line of credit facility, unused capacity, commitment fee percentage	0.25%
Revolving Credit Facility [Member] \| ETP [Member]
Amount Outstanding	$ 314,400	$ 402,327
Letters of credit outstanding, amount	$ 25,600
Weighted average interest rate on amount outstanding	1.78%
Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Revolving credit facility	$ 200,000
Federal Funds Effective Rate [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Debt instrument, basis spread on variable rate	0.50%
LIBOR [Member] \| ETP Credit Facility [Member]
Debt instrument, basis spread on variable rate	1.50%
LIBOR [Member] \| Revolving Credit Facility [Member] \| ETE Senior Secured Revolving Credit Facilities [Member]
Debt instrument, basis spread on variable rate	1.00%

Debt Obligations (Regency Credit Facility) (Narrative) (Details) - Regency Credit Facility [Member] $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($)
Revolving commitments	$ 900.0
Letters of credit availablity	200.0
Revolving credit facility maximum allowable additional investments	$ 250.0
Debt instrument, maturity date	Jun. 15, 2014
Line of credit facility fronting fee percentage	0.125%
Outstanding borrowings	$ 332.0
Letters of credit outstanding, amount	19.0
Amount available for future borrowings	$ 549.0
Weighted average interest rate on amount outstanding	3.18%
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	0.375%
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 Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2011
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

Redeemable Preferred Units (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2010	May 25, 2010
Aggregate liquidation preference	$ 300,000	$ 300,000
Preferrred Units Issued Stated Price	$ 100	$ 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		$ 5,300	$ 12,700
Preferred units, fair value	$ 322,900	$ 322,900	$ 317,600
Regency Preferred Units [Member]
Quarterly cash distribution, per preferred unit		$ 0.445
Preferred units outstanding	4,371,586	4,371,586	4,371,586	4,371,586
Common units issued upon conversion		4,632,389
Subsidiary preferred unit mandatory redemption date	9/2/2029	9/2/2029
Mandatory redeemable price of units outstanding	$ 71,144	$ 71,144	$ 70,943	$ 70,793
Regency Mandatorily Redeemable Amount At Expiration [Member]
Mandatory redeemable price of units outstanding	$ 80,000	$ 80,000

Redeemable Preferred Units Schedule Of Redeemable Preferred Units (Details) - Regency Preferred Units [Member] - USD ($) $ in Thousands	7 Months Ended	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2011	May 25, 2010
Preferred Units [Line Items]
Preferred Units, Outstanding	4,371,586	4,371,586	4,371,586
Preferred Units Redemption Amount	$ 70,943	$ 71,144	$ 70,793
Accretion to Redemption Value, Adjustment	$ 150	$ 201

Equity (Narrative) (Details) - USD ($)
$ in Thousands

1 Months Ended

12 Months Ended

Nov. 30, 2011

Oct. 31, 2011

May 31, 2011

Apr. 30, 2011

Aug. 31, 2010

Jan. 31, 2010

Oct. 31, 2009

Apr. 30, 2009

Jan. 31, 2009

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Sep. 30, 2011

Dec. 31, 2008

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

222,972,708

222,941,172

222,898,248

222,829,956

Limited Partner interest in the Partnership, percentage

99.69%

Gain from subsidiary issuances of common units

$ 153,039

$ 352,307

$ 96,996

Required contribution to subsidiary

12,300

General Partner Contribution Payable

$ 8,900

ETP [Member]

Common units issued through public offering

^[1]

15,237,500

14,202,500

10,925,000

9,775,000

6,900,000

9,775,000

6,900,000

Proceeds from issuance of common units

$ 660,241

^[2],[3]

$ 695,496

^[2]

$ 489,418

^[2],[3]

$ 423,551

^[2],[3]

$ 275,979

^[3]

$ 352,369

^[2]

$ 225,354

^[3]

Equity Distribution Agreement, maximum aggregate value of common units sold

$ 200,000

ETP [Member] | UBS [Member]

Proceeds from issuance of common units

$ 214,300

ETP [Member] | Distribution Reinvestment Plan [Member]

Common units issued through public offering

5,750,000

Value of units issued during period through DRIP

$ 15,000

Units issued during period through DRIP

353,679

ETP [Member] | Credit Suisse [Member]

Proceeds from issuance of common units

$ 96,300

Equity Distribution Agreement, remaining aggregate value to be sold

$ 69,600

Regency [Member]

Common units issued through public offering

11,500,000

17,537,500

Common units issued through private placement

8,500,001

Proceeds from issuance of common units

$ 231,900

$ 203,900

$ 400,200

Lone Star L.L.C. [Member] | ETP [Member]

Subsidiary Interest in Joint Venture

70.00%

Lone Star L.L.C. [Member] | Regency [Member]

Subsidiary Interest in Joint Venture

30.00%

[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 Units) (Details) - shares	12 Months Ended
Equity (Change In ETE Common Units) (Details) - shares	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Partners' Capital Notes [Abstract]
Number of Common Units, beginning of period	222,941,172	222,898,248	222,829,956
Issuance of restricted Common Units under long-term incentive plans	31,536	42,924	68,292
Number of Common Units, end of period	222,972,708	222,941,172	222,898,248

Equity Equity (Schedule Of Common Units Sold In Public Offering) (Details) - ETP [Member] - USD ($)
$ / shares in Units, $ in Thousands

1 Months Ended

Nov. 30, 2011

Apr. 30, 2011

Aug. 31, 2010

Jan. 31, 2010

Oct. 31, 2009

Apr. 30, 2009

Jan. 31, 2009

Capital Unit [Line Items]

Number of ETP Common Units

^[1]

15,237,500

14,202,500

10,925,000

9,775,000

6,900,000

9,775,000

6,900,000

Price per ETP Unit

$ 44.67

$ 50.52

$ 46.22

$ 44.72

$ 41.27

$ 37.55

$ 34.05

Net Proceeds

$ 660,241

^[2],[3]

$ 695,496

^[2]

$ 489,418

^[2],[3]

$ 423,551

^[2],[3]

$ 275,979

^[3]

$ 352,369

^[2]

$ 225,354

^[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 Of Available Cash) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended													12 Months Ended
	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, 2011	Dec. 31, 2010	Dec. 31, 2009
Partners' Capital Account, Distributions														$ 525,596	$ 483,048	$ 470,658
Parent Company [Member]
Limited Partners' Capital Account, Distribution Amount														$ 542,939	481,554	475,911
Quarter Ended		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
Record Date		November 4, 2011	August 5, 2011	May 6, 2011	February 7, 2011	November 8, 2010	August 9, 2010	May 7, 2010	February 8, 2010	November 9, 2009	August 7, 2009	May 8, 2009	February 6, 2009
Payment Date		November 18, 2011	August 19, 2011	May 19, 2011	February 18, 2011	November 19, 2010	August 19, 2010	May 19, 2010	February 19, 2010	November 19, 2009	August 19, 2009	May 19, 2009	February 19, 2009
Distributions paid, rate per unit	$ 0.625	$ 0.6250	$ 0.6250	$ 0.5600	$ 0.5400	$ 0.5400	$ 0.5400	$ 0.5400	$ 0.5400	$ 0.5350	$ 0.5350	$ 0.5250	$ 0.5100	$ 2.50
General Partners' Capital Account, Period Distribution Amount														$ 1,685	1,495	1,478
Incentive Distribution, Distribution														$ 544,624	483,049	477,389
ETP [Member]
Quarter Ended		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
Record Date		November 4, 2011	August 5, 2011	May 6, 2011	February 7, 2011	November 8, 2010	August 9, 2010	May 7, 2010	February 8, 2010	November 9, 2009	August 7, 2009	May 8, 2009	February 6, 2009
Payment Date		November 14, 2011	August 15, 2011	May 16, 2011	February 14, 2011	November 15, 2010	August 16, 2010	May 17, 2010	February 15, 2010	November 16, 2009	August 14, 2009	May 15, 2009	February 13, 2009
Distributions paid, rate per unit	0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.89375	$ 3.575
General Partners' Capital Account, Period Distribution Amount														$ 19,603	19,524	19,505
Incentive Distribution, Distribution														421,888	375,979	350,486
Partners' Capital Account, Distributions														1,216,325	1,084,785	1,011,738
Regency [Member]
Limited Partners' Capital Account, Distribution Amount														$ 274,538	175,360
Quarter Ended		Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010
Record Date		November 7, 2011	August 5, 2011	May 6, 2011	February 7, 2011	November 5, 2010	August 6, 2010
Payment Date		November 14, 2011	August 12, 2011	May 13, 2011	February 14, 2011	November 12, 2010	August 13, 2010
Distributions paid, rate per unit	$ 0.46	$ 0.455	$ 0.450	$ 0.445	$ 0.445	$ 0.445	$ 0.445							$ 1.84
General Partners' Capital Account, Period Distribution Amount														$ 5,185	3,640
Incentive Distribution, Distribution														6,057	3,016
Partners' Capital Account, Distributions														285,780	182,016
Common Units [Member] \| ETP [Member]
Limited Partners' Capital Account, Distribution Amount														762,350	676,798	629,263
Class E Units [Member] \| ETP [Member]
Limited Partners' Capital Account, Distribution Amount														$ 12,484	$ 12,484	$ 12,484

Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Partners' Capital Notes [Abstract]
Net gains on commodity related hedges	$ 1,696	$ 14,146
Unrealized gains on available-for-sale securities	114	918
Subtotal	1,810	15,064
Amounts attributable to noncontrolling interest	(1,132)	(10,266)
Total AOCI included in partners' capital, net of tax	$ 678	$ 4,798

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 14, 17, 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 31
-Article 5

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e637-108580

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e681-108580

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e653-108580

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS115-1/124-1
-Paragraph 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

This element represents Other Comprehensive Income or Loss, Net of Tax, for the period attributable to noncontrolling interest. Includes deferred gains or losses on qualifying hedges, unrealized holding gains or losses on available-for-sale securities, minimum pension liability, and cumulative translation adjustment.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 30
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 29
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 45
-Paragraph 20
-URI http://asc.fasb.org/extlink&oid=6921628&loc=SL4569643-111683

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 45
-Paragraph 19
-URI http://asc.fasb.org/extlink&oid=6921628&loc=SL4569616-111683

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6921930&loc=SL4573702-111684

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph c(3)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Unit-Based Compensation Plans (Details)	12 Months Ended
Unit-Based Compensation Plans (Details)	Dec. 31, 2011 USD ($) years $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares
Affiliated Entity [Member]
Vesting Period	5
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	2,853,676
Unvested awards	30,000
Grant Date Fair Value Per Unit \| $ / shares	$ 39.82
Vesting Period	5
Percentage Of Units Vesting In Current Year	20.00%
Units Vested In Period		24,897
Fair Value Of Units As Of The Vesting Date \| $		$ 1,000,000
Preferred Units, Outstanding		82,557
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized \| $	$ 1,200,000
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	2.0
ETP Unit-Based Compensation Plans [Member]
Unvested awards	2,563,709	1,936,578
Grant Date Fair Value Per Unit \| $ / shares	$ 46.37	$ 43.95
Vesting Period	5
Percentage Of Units Vesting In Current Year	20.00%
Units Vested In Period	(610,557)
Fair Value Of Units As Of The Vesting Date \| $	$ 26,900,000	$ 16,500,000	$ 14,700,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized \| $	$ 79,400,000
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term \| years	1.9
Granted unvested awards \| $ / shares	$ 48.35	$ 49.82	$ 43.56
Preferred units carrying value non-cash adjustment \| $	$ 2,000,000	$ 3,700,000	$ 6,400,000
Regency Common Unit Options [Member]
Unvested awards	0
Exercisable at the end of the period, Units	156,850
Options, Outstanding, Weighted Average Exercise Price \| $ / shares	$ 21.99
Regency Phantom Units [Member]
Unvested awards	1,086,393
Grant Date Fair Value Per Unit \| $ / shares	$ 24.51
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized \| $	$ 20,700,000
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition \| $	4.2
ETE Common Units [Member]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized \| $	$ 1,000,000
Common Units Outstanding	180,000
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition \| years	1.0
Regency [Member]
Conversion Of Phantom Units To Common Units	252,630

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] - $ / shares	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	2,563,709	1,936,578
Weighted Average Grant-Date Fair Value Per ETP Unit	$ 46.37	$ 43.95
Awards granted	1,386,251
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$ 48.35	$ 49.82	$ 43.56
Awards vested	(610,557)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards vested	$ 44.07
Awards forfeited	(148,563)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards forfeited	$ 42.74

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details) $ in Millions		1 Months Ended	12 Months Ended
	Jan. 12, 2012 USD ($)	Jul. 31, 2011 USD ($)	Dec. 31, 2011 USD ($) years sites	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Typical length of purchase and supply agreements (in years) \| years			1
Maximum lease expiration year			2029
Operating leases rent expense			$ 29.3	$ 23.8	$ 19.8
Long-term purchase contract agreement, expiration date			March 1, 2015
Sites where remediation operations are responsibility of third parties \| sites			6
Capital costs			$ 18.3	13.3	31.4
Operating and maintenance costs			14.7	15.4	$ 18.5
AmeriGas [Member]
Proceeds from (Repayments of) Related Party Debt	$ 1,500.0
ETP [Member]
Accrual for environmental loss contingencies			13.7	13.8
FEP Facility [Member]
Capital contribution from joint venture interest holders		$ 390.0
Proceed from loan credit facility			600.0
Revolving credit facility			$ 1,100.0
Debt instrument, maturity date			Jul. 01, 2012
July 2015 [Member]
Revolving credit facility			$ 50.0
Debt instrument, maturity date			Jul. 01, 2015
ETP Guarantee [Member] \| FEP Facility [Member]
Interest ownership			50.00%
Line of credit facility obligation rate			50.00%
Related To Deductibles [Member]
Accrual for loss contingency			$ 18.2	10.2
Contingencies And Litigation Matters Other Than Accruals Related To Environmental Matters And Deductibles [Member]
Accrual for loss contingency			$ 0.0	0.0
Future Estimated Cost Of Remediation Activities [Member] \| Transwestern [Member] \| ETP [Member]
Year remediation activities expected to continue through			2025
Components of accrual for environmental loss contingencies			$ 5.7
Accrual For Six Sites [Member]
Components of accrual for environmental loss contingencies			$ 0.0	$ 0.0
Sale [Member] \| 6.75% Senior Notes Due 2020 [Member] \| AmeriGas Finance LLC [Member]
Aggregate principal amount	$ 550.0
Debt Instrument, Interest Rate, Stated Percentage	6.75%
Sale [Member] \| 7.00% Senior Notes Due 2022 [Member] \| AmeriGas Finance LLC [Member]
Aggregate principal amount	$ 1,000.0
Debt Instrument, Interest Rate, Stated Percentage	7.00%

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Schedule of Future Minimum Rental Payments for Operating Leases) (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Operating Leased Assets [Line Items]
2012	$ 22,480
2013	20,667
2014	17,467
2015	17,292
2016	17,283
Thereafter	$ 152,473

Price Risk Management Assets And Liabilities (Narrative) (Details) $ in Thousands	1 Months Ended		12 Months Ended
	Sep. 30, 2010 USD ($)	May 31, 2010 USD ($)	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Amortization period of deferred losses on discontinuation of cash flow hedge, years \| years			2.25
Swap maturity term (years) \| years			10
Payment To Terminate Non Hedged Interest Rate Swaps	$ 102,200
Proceeds Payments From Termination Of Swaps		$ 168,600	$ 0	$ (26,495)	$ 0
Deposits with counterparties			66,231	52,192
Unrealized gains (losses) on commodity derivatives			(20,800)	(70,500)	(18,600)
ETP [Member]
Expected gains (losses) related to commodity derivatives to be reclassified into earnings over next year related to amounts currently reported in AOCI			6,400
Regency [Member]
Expected gains (losses) related to commodity derivatives to be reclassified into earnings over next year related to amounts currently reported in AOCI			(5,200)
Net hedging losses in accumulated other comprehensive income			(4,800)
Commodity Derivatives [Member]
Unrealized gains (losses) on commodity derivatives and related hedged inventory			$ 9,500	$ 17,400	$ 48,600
Interest Rate Derivatives [Member] \| ETE [Member]
Notional Amount of Derivatives	1,500,000
Interest Expense [Member] \| Interest Rate Derivatives [Member] \| ETE [Member]
Cash Flow Hedge Loss Reclassified to Interest Expense	$ 66,400

Price Risk Management Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) - Interest Rate Derivatives [Member] - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

May 2012 [Member] | ETP [Member]

Term

^[1]

May 2012 (2)

Notional Amount

$ 350,000

$ 0

Type

^[2]

Forward starting to pay a fixed rate of 2.59% and receive a floating rate

Interest rate swaps, fixed rate

2.59%

August 2012 [Member] | ETP [Member]

Term

^[1]

August 2012 (2)

Notional Amount

$ 500,000

400,000

Type

^[2]

Forward starting to pay a fixed rate of 3.51% and receive a floating rate

Interest rate swaps, fixed rate

3.51%

July 2013 [Member] | ETP [Member]

Term

^[1]

July 2013 (2)

Notional Amount

$ 300,000

Type

^[2]

Forward starting to pay a fixed rate of 4.02% and receive a floating rate

Interest rate swaps, fixed rate

4.02%

July 2018 [Member] | ETP [Member]

Term

July 2018

Notional Amount

$ 500,000

500,000

Type

^[2]

Pay a floating rate plus a spread of 4.01% and receive a fixed rate of 6.70%

Interest rate swaps, spread on floating rate

4.01%

Interest rate swaps, fixed rate

6.70%

April 2012 [Member] | Regency [Member]

Term

April 2012

Notional Amount

$ 250,000

Type

^[2]

Pay a fixed rate of 1.325% and receive a floating rate

Interest rate swaps, fixed rate

1.325%

[1]	Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.
[2]	Floating rates are based on LIBOR.

Price Risk Management Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Total derivatives assets	$ 346,391	$ 130,299
Total derivatives liabilities	(423,598)	(171,997)
Designated as Hedging Instrument [Member]
Total derivatives assets	81,736	44,294
Total derivatives liabilities	(10,947)	(21,323)
Designated as Hedging Instrument [Member] \| Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	77,197	35,031
Total derivatives liabilities	(819)	(6,631)
Designated as Hedging Instrument [Member] \| Commodity Derivatives [Member]
Total derivatives assets	4,539	9,263
Total derivatives liabilities	(10,128)	(14,692)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	264,655	86,005
Total derivatives liabilities	(412,651)	(150,674)
Not Designated as Hedging Instrument [Member] \| Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	227,337	64,940
Total derivatives liabilities	(251,268)	(72,729)
Not Designated as Hedging Instrument [Member] \| Commodity Derivatives [Member]
Total derivatives assets	1,017	275
Total derivatives liabilities	(4,844)	0
Not Designated as Hedging Instrument [Member] \| Interest Rate Derivatives [Member]
Total derivatives assets	36,301	20,790
Total derivatives liabilities	(117,490)	(20,922)
Not Designated as Hedging Instrument [Member] \| Embedded Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ (39,049)	$ (57,023)

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 6,369	$ 19,685	$ (11,562)
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	6,369	49,665	3,143
Interest Rate Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ (29,980)	$ (14,705)

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$ 18,685	$ (49,372)	$ (16,958)
Amount of Gain/(Loss) Recognized in Income on Ineffective Portion	286	(70)	0
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	34,000	16,210	60,045
Amount of Gain/(Loss) Recognized in Income on Derivatives	(80,408)	(56,941)	133,426
Commodity Derivatives [Member] \| Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	18,685	37,325	9,924
Amount of Gain/(Loss) Recognized in Income on Ineffective Portion	286	(70)	0
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	34,000	16,210	60,045
Interest Rate Derivatives [Member] \| Interest Expense [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	0	(86,697)	(26,882)
Interest Rate Derivatives [Member] \| Losses On Non-Hedged Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(77,804)	(52,357)	33,619
Embedded Derivatives [Member] \| Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	17,974	(8,390)	0
Non Trading [Member] \| Commodity Derivatives [Member] \| Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	9,199	3,806	99,807
Trading [Member] \| Commodity Derivatives [Member] \| Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (29,777)	$ 0	$ 0

Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	7 Months Ended	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Retirement Benefits [Line Items]
Contributions by employer, defined contribution plan		$ 14.0
ETP [Member]
Retirement Benefits [Line Items]
Contributions by employer, defined contribution plan			$ 9.8	$ 9.8
Regency [Member]
Retirement Benefits [Line Items]
Contributions by employer, defined contribution plan	$ 2.0

Related Party Transactions (Narrative) (Details) gal in Millions, $ in Millions	7 Months Ended	12 Months Ended
	Dec. 31, 2010 USD ($) gal	Dec. 31, 2011 USD ($) gal	Dec. 31, 2010 USD ($) gal	Dec. 31, 2009 USD ($)	Jan. 18, 2012
Long-term purchase contract agreement, expiration date		March 1, 2015
ETP [Member]
General and administrative services paid		$ 17.1	$ 6.3	$ 0.5
General administrative expenses reimbursed		6.6
Operating leases, future annual payments due through 2017		4.7
Regency [Member]
General and administrative revenues		16.6	5.8
FEP [Member]
Revenue		1.9	26.0
Cost of sales		1.2	20.5
ETP Subsidiary [Member] \| Enterprise [Member]
Fair value of derivative assets	$ 0.2	4.1	0.2
Fair value of derivative assets accounted for as cash flow hedges	6.6		$ 6.6
HPC [Member] \| Regency [Member]
General administrative expenses reimbursed	9.8	16.8
Revenue	13.2	25.4
Cost of sales	$ 8.1	$ 14.3
Gallons Of Propane [Member] \| ETP Subsidiary [Member]
Forward Mark To Market Derivatives Outstanding \| gal	1.7	38.8	1.7
Gallons Of Propane [Member] \| ETP Subsidiary [Member] \| Enterprise [Member]
Forward derivatives accounted for as cash flow hedges \| gal	32.5		32.5
Sale [Member] \| Enterprise [Member]
Noncontrolling interest, ownership percentage by noncontrolling owners					5.00%

Related Party Transactions (Sales To And Purchase From Affiliates Of Enterprise) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
ETP's Natural Gas Operations [Member]
Sales	$ 654,129	$ 538,657	$ 414,333
Purchases	26,992	23,592	48,528
Regency's Natural Gas Operations [Member]
Sales	376,542	142,631	0
Purchases	9,427	4,606	0
ETP's Propane Operations [Member]
Sales	10,613	15,527	19,961
Purchases	$ 471,046	$ 415,897	$ 343,540

Related Party Transactions (Related Party Receivables And Payables) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Accounts receivable from related parties	$ 100,406	$ 76,331
Accounts payable to related parties	33,208	27,351
ETP's Natural Gas Operations [Member]
Accounts receivable from related parties	54,644	36,736
Accounts payable to related parties	2,198	2,687
Regency's Natural Gas Operations [Member]
Accounts receivable from related parties	41,781	25,539
Accounts payable to related parties	1,469	1,323
ETP's Propane Operations [Member]
Accounts receivable from related parties	0	2,327
Accounts payable to related parties	27,770	22,985
Other Operations [Member]
Accounts receivable from related parties	3,981	11,729
Accounts payable to related parties	1,771	356
Enterprise [Member] \| ETP [Member]
Net imbalance (payable to) receivable from Enterprise	(780)	1,360
Enterprise [Member] \| Regency [Member]
Net imbalance (payable to) receivable from Enterprise	$ 2,008	$ 753

Reportable Segments (Operating Segments) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues from external customers	$ 2,178,811	$ 2,097,866	$ 1,974,906	$ 1,989,120	$ 1,775,815	$ 1,587,807	$ 1,362,529	$ 1,871,981	$ 8,240,703	$ 6,598,132	$ 5,417,295
Intersegment revenues									0	0	0
Depreciation and amortization									611,809	431,199	325,024
Interest Expense									739,811	624,887	468,420
Equity in earnings of affiliates									117,188	65,220	20,597
Income tax expense (benefit)									16,883	13,738	9,229
Net income (loss)									528,247	336,580	697,871
Investment In ETP [Member]
Revenue from external customers									6,812,431	5,884,786	5,417,295
Intersegment revenues									38,009	41	0
Depreciation and amortization									430,904	343,011	312,803
Interest Expense									474,113	412,553	394,274
Equity in earnings of affiliates									25,836	11,727	20,597
Income tax expense (benefit)									18,815	15,536	12,777
Net income (loss)									697,162	617,222	791,542
Investment In Regency [Member]
Revenue from external customers									1,425,859	715,324	0
Intersegment revenues									8,039	1,289	0
Depreciation and amortization									168,684	75,967	0
Interest Expense									102,474	48,251	0
Equity in earnings of affiliates									119,540	53,493	0
Income tax expense (benefit)									465	552	0
Net income (loss)									73,619	(5,972)	0
Corporate And Other [Member]
Revenue from external customers									0	0	0
Intersegment revenues									0	0	0
Depreciation and amortization									12,221	12,221	12,221
Interest Expense									163,622	167,669	74,146
Equity in earnings of affiliates									0	0	0
Income tax expense (benefit)									(2,397)	(2,350)	(3,548)
Net income (loss)									(214,346)	(274,670)	(93,671)
Adjustments And Eliminations [Member]
Revenue from external customers									2,413	(1,978)	0
Intersegment revenues									(46,048)	(1,330)	0
Depreciation and amortization									0	0	0
Interest Expense									(398)	(3,586)	0
Equity in earnings of affiliates									(28,188)	0	0
Income tax expense (benefit)									0	0	0
Net income (loss)									$ (28,188)	$ 0	$ 0

Reportable Segments (Assets Segments)(Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Assets	$ 20,896,793	$ 17,378,730	$ 12,160,509
Investment In ETP [Member]
Assets	15,518,616	12,149,992	11,734,972
Investment In Regency [Member]
Assets	5,567,856	4,770,204	0
Corporate And Other [Member]
Assets	470,086	469,221	431,109
Adjustments And Eliminations [Member]
Assets	$ (659,765)	$ (10,687)	$ (5,572)

Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Segment Reporting Information [Line Items]

Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):

$ 3,332,679

$ 3,538,329

$ 680,780

Investment in ETP [Member]

Segment Reporting Information [Line Items]

Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):

^[1]

2,921,865

1,470,001

680,780

Investment in Regency [Member]

Segment Reporting Information [Line Items]

Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):

^[2]

$ 410,814

$ 2,068,328

$ 0

[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.

Reporting Segments (Advances To And Investments In Affiliates Segments) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Advance to and investments in affiliates:	$ 1,496,600	$ 1,359,979	$ 663,298
Investment in ETP [Member]
Segment Reporting Information [Line Items]
Advance to and investments in affiliates:	200,612	8,723	663,298
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Advance to and investments in affiliates:	1,924,705	1,351,256	0
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Advance to and investments in affiliates:	$ (628,717)	$ 0	$ 0

Reportable Segments (Revenues By Similar Products And Services) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2011	Dec. 31, 2010	Dec. 31, 2009
Total revenues	$ 2,178,811	$ 2,097,866	$ 1,974,906	$ 1,989,120	$ 1,775,815	$ 1,587,807	$ 1,362,529	$ 1,871,981	$ 8,240,703	$ 6,598,132	$ 5,417,295
ETP [Domain]
Total revenues									6,850,440	5,884,827	5,417,295
Regency [Domain]
Total revenues									1,433,898	716,613	0
Intrastate Transportation And Storage [Member] \| ETP [Domain]
Total revenues									2,397,887	2,075,217	1,773,528
Interstate Transportation [Member] \| ETP [Domain]
Total revenues									446,743	292,419	270,213
Midstream [Member] \| ETP [Domain]
Total revenues									2,041,600	1,955,627	2,060,451
NGL Transportation And Services [Member] \| ETP [Domain]
Total revenues									362,701	0	0
Retail Propane And Other Retail Propane Related [Member] \| ETP [Domain]
Total revenues									1,468,082	1,419,646	1,292,583
All Other [Member] \| ETP [Domain]
Total revenues									133,427	141,918	20,520
Gathering And Processing [Member] \| Regency [Domain]
Total revenues									1,226,260	606,944	0
Joint Ventures [Member] \| Regency [Domain]
Total revenues									0	0	0
Contract Compression [Member] \| Regency [Domain]
Total revenues									150,496	86,099	0
Contract Treating [Member] \| Regency [Domain]
Total revenues									39,604	13,662	0
Corporate And Others [Member] \| Regency [Domain]
Total revenues									$ 17,538	$ 9,908	$ 0

Quarterly Financial Data (Unaudited) (Schedule of Quarterly Financial Information) (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011 USD ($) $ / shares	Sep. 30, 2011 USD ($) $ / shares	Jun. 30, 2011 USD ($) $ / shares	Mar. 31, 2011 USD ($) $ / shares	Dec. 31, 2010 USD ($) $ / shares	Sep. 30, 2010 USD ($) $ / shares	Jun. 30, 2010 USD ($) $ / shares	Mar. 31, 2010 USD ($) $ / shares	Dec. 31, 2011 USD ($) $ / shares	Dec. 31, 2010 USD ($) $ / shares	Dec. 31, 2009 USD ($) $ / shares
Revenues	$ 2,178,811	$ 2,097,866	$ 1,974,906	$ 1,989,120	$ 1,775,815	$ 1,587,807	$ 1,362,529	$ 1,871,981	$ 8,240,703	$ 6,598,132	$ 5,417,295
Gross margin	814,427	744,829	710,754	787,694	724,902	592,702	522,075	647,116	3,057,704	2,486,795
Operating income	340,007	270,008	260,561	364,243	316,492	202,052	179,257	338,928	1,234,819	1,036,729	1,110,398
Net income (loss)									528,247	336,580	697,871
Net Income (Loss) Allocated to Limited Partners	$ 85,537	$ 68,869	$ 66,080	$ 88,366	$ 75,814	$ (15,289)	$ 19,208	$ 112,428	$ 308,852	$ 192,161	$ 441,103
BASIC NET INCOME PER LIMITED PARTNER UNIT \| $ / shares	0.38	0.31	0.30	0.40	0.34	(0.07)	0.09	0.50	1.39	0.86	1.98
DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT \| $ / shares	0.38	0.31	0.30	0.40	0.34	(0.07)	0.09	0.50	1.38	0.86	1.98

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 29
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A1, A4, A5
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 5
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=6922042&loc=SL4591552-111686

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 45
-Paragraph 19
-URI http://asc.fasb.org/extlink&oid=6921628&loc=SL4569616-111683

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=6922042&loc=SL4591551-111686

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-Subparagraph (a),(c)
-URI http://asc.fasb.org/extlink&oid=6921930&loc=SL4573702-111684

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph c(1)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Supplemental Financial Statement Information (Schedule Of Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Cash and cash equivalents	$ 126,342	$ 86,264	$ 68,315	$ 92,023
Accounts receivable from related companies	100,406	76,331
Other current assets	181,904	109,359
Total current assets	1,455,444	1,291,010
ADVANCES TO AND INVESTMENTS IN AFFILIATES	1,496,600	1,359,979	663,298
Total assets	20,896,793	17,378,730	12,160,509
Accounts payable	512,023	421,556
Accounts payable to related companies	33,208	27,351
Accrued and other current liabilities	763,912	567,688
Total current liabilities	1,841,313	1,081,075
LONG-TERM DEBT, less current maturities	10,946,864	9,346,067
SERIES A CONVERTIBLE PREFERRED UNITS	71,144	70,943
COMMITMENTS AND CONTINGENCIES
General Partner	321	520
Limited Partners - Common Unitholders (222,972,708 and 222,941,172 units authorized, issued and outstanding at December 31, 2011 and 2010, respectively)	52,485	115,350
Accumulated other comprehensive income	678	4,798
Total partners' capital	53,484	120,668
Total liabilities and equity	20,896,793	17,378,730
Parent Company [Member]
Cash and cash equivalents	18,460	27,247	$ 62	$ 62
Accounts receivable from related companies	1,456	171
Other current assets	714	864
Total current assets	20,630	28,282
ADVANCES TO AND INVESTMENTS IN AFFILIATES	2,225,572	2,231,722
INTANGIBLES AND OTHER ASSETS, net	49,906	29,118
Total assets	2,296,108	2,289,122
Accounts payable	174	0
Accounts payable to related companies	12,334	6,654
Accrued and other current liabilities	35,706	44,200
Total current liabilities	48,214	50,854
LONG-TERM DEBT, less current maturities	1,871,500	1,800,000
SERIES A CONVERTIBLE PREFERRED UNITS	322,910	317,600
COMMITMENTS AND CONTINGENCIES
General Partner	321	520
Limited Partners - Common Unitholders (222,972,708 and 222,941,172 units authorized, issued and outstanding at December 31, 2011 and 2010, respectively)	52,485	115,350
Accumulated other comprehensive income	678	4,798
Total partners' capital	53,484	120,668
Total liabilities and equity	$ 2,296,108	$ 2,289,122

Supplemental Financial Statement Information (Schedule Of Statements Of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2011	Dec. 31, 2010	Dec. 31, 2009
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									$ (292,158)	$ (234,321)	$ (178,924)
InterestExpense									739,811	624,887	468,420
Equity in earnings of affiliates									117,188	65,220	20,597
Losses on non-hedged interest rate derivatives									(77,806)	(52,357)	33,619
Other, net									15,954	(44,210)	1,913
Income tax expense (benefit)									16,883	13,738	9,229
NET INCOME ATTRIBUTABLE TO PARTNERS									309,811	192,758	442,473
GENERAL PARTNER'S INTEREST IN NET INCOME									959	597	1,370
LIMITED PARTNERS' INTEREST IN NET INCOME	$ 85,537	$ 68,869	$ 66,080	$ 88,366	$ 75,814	$ (15,289)	$ 19,208	$ 112,428	308,852	192,161	441,103
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									(29,641)	(21,829)	(4,970)
InterestExpense									163,612	167,658	74,049
Equity in earnings of affiliates									509,361	455,901	526,383
Losses on non-hedged interest rate derivatives									0	(53,388)	(5,620)
Other, net									(5,796)	(19,721)	79
INCOME BEFORE INCOME TAXES									310,312	193,305	441,823
Income tax expense (benefit)									501	547	(650)
NET INCOME ATTRIBUTABLE TO PARTNERS									309,811	192,758	442,473
GENERAL PARTNER'S INTEREST IN NET INCOME									959	597	1,370
LIMITED PARTNERS' INTEREST IN NET INCOME									$ 308,852	$ 192,161	$ 441,103

Supplemental Financial Statement Information (Schedule Of Statements Of Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$ 1,376,691	$ 1,086,879	$ 723,461
Net cash used in investing activities	(3,872,882)	(1,829,979)	(1,345,756)
Proceeds from borrowings	8,261,905	4,388,531	3,542,612
Principal payments on debt	(6,263,802)	(4,078,171)	(3,020,587)
Distributions to partners	(525,596)	(483,048)	(470,658)
Debt issuance costs	(53,298)	(48,613)	(7,646)
Net cash provided by financing activities	2,536,269	761,049	598,587
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	40,078	17,949	(23,708)
CASH AND CASH EQUIVALENTS, beginning of period	86,264	68,315	92,023
CASH AND CASH EQUIVALENTS, end of period	126,342	86,264	68,315
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	469,004	317,328	468,969
MEP Transaction	0	3,258	0
Net cash used in investing activities	0	3,258	0
Proceeds from borrowings	91,500	1,858,245	67,505
Principal payments on debt	(20,000)	(1,632,374)	(65,816)
Distributions to partners	(525,596)	(483,048)	(470,658)
Debt issuance costs	(23,695)	(36,224)	0
Net cash provided by financing activities	(477,791)	(293,401)	(468,969)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(8,787)	27,185	0
CASH AND CASH EQUIVALENTS, beginning of period	27,247	62	62
CASH AND CASH EQUIVALENTS, end of period	$ 18,460	$ 27,247	$ 62

Price Risk Management Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)	Dec. 31, 2011 bbl gal MMbtu	Dec. 31, 2010 bbl gal MMbtu
Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Swing Swaps IFERC (MMBtu) [Member] \| ETP [Member]
Notional Volume	92,370,000	(19,720,000)
Maturity		2011
Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Fixed Swaps/Futures (MMBtu) [Member] \| ETP [Member]
Notional Volume	797,500	(2,570,000)
Maturity	2012	2011
Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Forward Physical Contracts (MMBtu) [Member] \| ETP [Member]
Notional Volume	(10,672,028)	0
Maturity	2012
Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Options - Calls (MMBtu) [Member] \| ETP [Member]
Notional Volume	0	(3,000,000)
Maturity		2011
Mark-To-Market Derivatives [Member] \| Propane [Member] \| Forwards/Swaps (Gallons) [Member] \| ETP [Member]
Notional Volume \| gal	38,766,000	1,974,000
Maturity		2011
Fair Value Hedging Derivatives [Member] \| Natural Gas [Member] \| Basis Swaps IFERC/NYMEX (MMBtu) [Member] \| ETP [Member]
Notional Volume	(28,752,500)	(28,050,000)
Maturity	2012	2011
Fair Value Hedging Derivatives [Member] \| Natural Gas [Member] \| Fixed Swaps/Futures (MMBtu) [Member] \| ETP [Member]
Notional Volume	(45,822,500)	(39,105,000)
Maturity	2012	2011
Fair Value Hedging Derivatives [Member] \| Natural Gas [Member] \| Hedged Item - Inventory (MMBtu) [Member] \| ETP [Member]
Notional Volume	45,822,500	39,105,000
Maturity	2012	2011
Cash Flow Hedging Derivatives [Member] \| Natural Gas [Member] \| Fixed Swaps/Futures (MMBtu) [Member] \| ETP [Member]
Notional Volume	0	(210,000)
Maturity		2011
Cash Flow Hedging Derivatives [Member] \| Natural Gas [Member] \| Fixed Swaps/Futures (MMBtu) [Member] \| Regency [Member]
Notional Volume	2,198,000	3,830,000
Maturity	2012	2011
Cash Flow Hedging Derivatives [Member] \| Natural Gas [Member] \| Options - Puts (MMBtu) [Member] \| ETP [Member]
Notional Volume	3,600,000	26,760,000
Maturity	2012
Cash Flow Hedging Derivatives [Member] \| Natural Gas [Member] \| Options - Calls (MMBtu) [Member] \| ETP [Member]
Notional Volume	(3,600,000)	(26,760,000)
Maturity	2012
Cash Flow Hedging Derivatives [Member] \| Propane [Member] \| Forwards/Swaps (Gallons) [Member] \| ETP [Member]
Notional Volume \| gal	0	32,466,000
Maturity		2011
Cash Flow Hedging Derivatives [Member] \| Propane [Member] \| Forwards/Swaps (Gallons) [Member] \| Regency [Member]
Notional Volume \| gal	11,802,000	18,648,000
Cash Flow Hedging Derivatives [Member] \| Natural Gas Liquids [Member] \| Forwards/Swaps (Barrels) [Member] \| Regency [Member]
Notional Volume \| bbl	533,000	1,212,110
Cash Flow Hedging Derivatives [Member] \| Natural Gas Liquids [Member] \| Options - Puts (Barrels) [Member] \| Regency [Member]
Notional Volume \| bbl	110,000
Maturity	2012
Cash Flow Hedging Derivatives [Member] \| WTI Crude Oil [Member] \| Forwards/Swaps (Barrels) [Member] \| Regency [Member]
Notional Volume \| bbl	350,000	373,655
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] \| Propane [Member] \| Forwards/Swaps (Gallons) [Member] \| ETP [Member]
Maturity	2013
Maximum [Member] \| Cash Flow Hedging Derivatives [Member] \| Natural Gas [Member] \| Options - Puts (MMBtu) [Member] \| ETP [Member]
Maturity		2012
Maximum [Member] \| Cash Flow Hedging Derivatives [Member] \| Natural Gas [Member] \| Options - Calls (MMBtu) [Member] \| ETP [Member]
Maturity		2012
Maximum [Member] \| Cash Flow Hedging Derivatives [Member] \| Propane [Member] \| Forwards/Swaps (Gallons) [Member] \| Regency [Member]
Maturity	2013	2012
Maximum [Member] \| Cash Flow Hedging Derivatives [Member] \| Natural Gas Liquids [Member] \| Forwards/Swaps (Barrels) [Member] \| Regency [Member]
Maturity	2013	2012
Maximum [Member] \| Cash Flow Hedging Derivatives [Member] \| WTI Crude Oil [Member] \| Forwards/Swaps (Barrels) [Member] \| Regency [Member]
Maturity	2014	2012
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] \| Propane [Member] \| Forwards/Swaps (Gallons) [Member] \| ETP [Member]
Maturity	2012
Minimum [Member] \| Cash Flow Hedging Derivatives [Member] \| Natural Gas [Member] \| Options - Puts (MMBtu) [Member] \| ETP [Member]
Maturity		2011
Minimum [Member] \| Cash Flow Hedging Derivatives [Member] \| Natural Gas [Member] \| Options - Calls (MMBtu) [Member] \| ETP [Member]
Maturity		2011
Minimum [Member] \| Cash Flow Hedging Derivatives [Member] \| Propane [Member] \| Forwards/Swaps (Gallons) [Member] \| Regency [Member]
Maturity	2012	2011
Minimum [Member] \| Cash Flow Hedging Derivatives [Member] \| Natural Gas Liquids [Member] \| Forwards/Swaps (Barrels) [Member] \| Regency [Member]
Maturity	2012	2011
Minimum [Member] \| Cash Flow Hedging Derivatives [Member] \| WTI Crude Oil [Member] \| Forwards/Swaps (Barrels) [Member] \| Regency [Member]
Maturity	2012	2011
Trading [Member] \| Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Basis Swaps IFERC/NYMEX (MMBtu) [Member] \| ETP [Member]
Notional Volume	(151,260,000)	0
Trading [Member] \| Maximum [Member] \| Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Basis Swaps IFERC/NYMEX (MMBtu) [Member] \| ETP [Member]
Maturity	2013
Trading [Member] \| Minimum [Member] \| Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Basis Swaps IFERC/NYMEX (MMBtu) [Member] \| ETP [Member]
Maturity	2012
Non Trading [Member] \| Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Basis Swaps IFERC/NYMEX (MMBtu) [Member] \| ETP [Member]
Notional Volume	(61,420,000)	(38,897,500)
Maturity		2011
Non Trading [Member] \| Maximum [Member] \| Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Basis Swaps IFERC/NYMEX (MMBtu) [Member] \| ETP [Member]
Maturity	2013
Non Trading [Member] \| Minimum [Member] \| Mark-To-Market Derivatives [Member] \| Natural Gas [Member] \| Basis Swaps IFERC/NYMEX (MMBtu) [Member] \| ETP [Member]
Maturity	2012